10-K 1 greka1202.txt 10-K U.S. Securities and Exchange Commission Washington, D.C. 20549 Form 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------- ------------ Commission File No.: 0-20760 GREKA Energy Corporation ---------------------------------------------- (Name of issuer in its charter) Colorado 84-1091986 ------------------------------ ---------------------- (State or other jurisdiction (I.R.S. Employer incorporation or organization) Identification Number) 630 Fifth Avenue, Suite 1501 New York, NY 10111 ----------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Issuer's telephone number: (212) 218-4680 Securities registered under Section 12(b) of the Exchange Act: None Securities registered under Section 12(g) of the Exchange Act: No Par Value Common Stock Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The issuer's revenues for 2002 were $28,910,845. The aggregate market value of 4,656,727 shares of common stock held by non-affiliates of the issuer, based on the closing bid price of the common stock on March 17, 2003 of $3.90 as reported on the Nasdaq National Market System and based on a total of 4,951,451 shares being outstanding on that date, was $19,310,659. (ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS) Check whether the issuer has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Exchange Act after the distribution of securities under a plan confirmed by a court. Yes [X] No [ ] Transitional Small Business Disclosure Format (check one). Yes [ ] No [X] Check whether the issuer is an accelerated filer (as defined in Rule 126-2 of the Act). Yes [ ] No [X] Table of Contents PART I ............................................................... 5 Item 1. Description of Business........................................ 5 Item 2. Description of Property........................................ 16 Item 3. Legal Proceedings.............................................. 23 Item 4. Submission of Matters to a Vote of Security Holders............ 23 PART II. ............................................................... 24 Item 5. Market for Common Equity and Related Stockholder Matters....... 24 Item 6. Selected Financial Data........................................ 25 Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations........................... 27 Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 31 Item 8. Financial Statements and Schedule.............................. 34 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures........................... 34 PART III. ............................................................... 35 Item 10. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of the Exchange Act.............. 35 Item 11. Executive Compensation......................................... 38 Item 12. Security Ownership of Certain Beneficial Owners and Management................................................. 40 Item 13. Certain Relationships and Related Transactions................. 42 Item 14. Controls and Procedures........................................ 42 Part IV. ............................................................... 43 Item 15. Exhibits and Reports on Form 8-K............................... 43 2 Definitions The terms below are used in this document and have specific Securities and Exchange Commission ("SEC") definitions as follows: Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs) as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery is included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units is claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. As used in this Form 10-K: "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Tcf" means trillion cubic feet, "Bbl" means barrel, "MBbls" means thousand barrels, "MMBbls" means million barrels, "BOE" means equivalent barrels of oil, "MBOE" means thousand equivalent barrels of oil and "MMBOE" means million equivalent barrels of oil. Unless otherwise indicated in this Form 10-K, gas volumes are stated at the legal pressure base of the state or area in which the reserves are located and at 60/o/ Fahrenheit. Equivalent barrels of oil are determined using the ratio of 6.0 Mcf of gas to 1 Bbl of oil, for the year ended December 31, 2002 and 5.5 Mcf of gas to 1 Bbl of oil for the years ended December 31, 2001 and 2000. The term "gross" refers to the total acres or wells in which the Company has a working interest, and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company. "Net production" means production that is owned by the Company less royalties and production due others. 3 Cautionary Information About Forward-Looking Statements This document contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements, other than statements of historical facts, included in or incorporated by reference into this Form 10-K which address activities, events or developments which the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. The words "believes," "intends," "expects," "anticipates," "projects," "estimates," "predicts" and similar expressions are also intended to identify forward-looking statements. These forward-looking statements include, among others, statements concerning: . the benefits expected to result from GREKA's 1999 acquisition of Saba Petroleum Company ("Saba") discussed below, including . synergies in the form of increased revenues, . decreased expenses and avoided expenses and expenditures that are expected to be realized as a result of the Saba acquisition, and . the complementary nature of GREKA's horizontal drilling technology and certain oil reserves acquired with the acquisition of Saba, and other statements of: . expectations, . anticipations, . beliefs, . estimations, . projections, and other similar matters that are not historical facts, including such matters as: . future capital, . development and exploration expenditures (including the timing, amount and nature thereof), . drilling and reworking of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), . future production of oil and gas, . repayment of debt, . business strategies, . oil, gas and asphalt prices and demand, . exploitation and exploration prospects, . expansion and other development trends of the oil and gas industry, and . expansion and growth of business operations. These statements are based on certain assumptions and analyses made by the management of GREKA in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. GREKA cautions the reader that these forward-looking statements are subject to risks and uncertainties, including those associated with: . our ability to refinance our debt on favorable terms, . our ability to successfully restructure our operations, . the financial environment, . general economic, market and business conditions, . the regulatory environment, . business opportunities that may be presented to and pursued by GREKA, . changes in laws or regulations . exploitation and exploration successes, . availability to obtain additional financing on favorable conditions, . trend projections, and . other factors, many of which are beyond GREKA's control that could cause actual events or results to differ materially from those expressed or implied by the statements. Such risks and uncertainties include those risks and uncertainties identified in the Description of the Business and Management's Discussion and Analysis sections of this document and risk factors discussed from time to time in the Company's filings with the Securities and Exchange Commission. 4 Significant factors that could prevent GREKA from achieving its stated goals include: . the inability of GREKA to obtain financing for capital expenditures and acquisitions, . declines in the market prices for oil, gas and asphalt, and . adverse changes in the regulatory environment affecting GREKA. The cautionary statements contained or referred to in this document should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by GREKA or persons acting on its or their behalf. GREKA undertakes no obligation to release publicly any revisions to any forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. PART I Item 1. Description of Business Overview of GREKA Energy Corporation GREKA Energy Corporation, a Colorado corporation ("GREKA" or the "Company") is an independent integrated energy company. Our oil and gas production, exploration and development activities are concentrated in our properties in California where we also own and operate an asphalt refinery. We supply our asphalt refinery with equity oil, which is the crude oil we produce from our surrounding heavy crude oil reserves, and we also utilize crude oil purchased from third party producers. We believe that our vertically integrated operations reduce our exposure to material volatile swings in crude oil prices. Historically we have also engaged in oil and gas exploration, development and production from our properties in Louisiana, Texas and New Mexico which operations have substantially been sold as part of our strategic, internal reorganization. In addition, we have interests in coalbed methane properties and production sharing contracts in China. We conduct our operations through two divisions: o Integrated Operations o International Operations Integrated Operations. Our wholly owned and operated consolidated assets in central California include substantial oil in place, over 1,200 wells, extensive pipeline and production facilities, and an infrastructure including 3 work-over rigs, approximately 17,700 mineral acres, approximately 3,300 acres of real estate, a 1-acre island connected to land by a 2,700' causeway containing the gas and oil pipelines and facilitating vehicular access, and an asphalt refinery. We own and operate an asphalt refinery located in Santa Maria, California. Crude oil that we produce from our surrounding heavy crude oil reserves supplies feedstock to the refinery. We supplement our equity oil production with third party feedstock to achieve efficiencies through lower refinery operating costs of finished product per unit. Our asphalt refinery produces 65% asphalt and 30% gas oil, with the remainder produced as naphtha. We sell our asphalt to hot mix asphalt producers, material supply companies and government agencies for use in road surfacing applications, and we sell the gas oil and naphtha to end users and refineries. The relatively stable price of asphalt and the low cost of our oil compared to third party feedstock reduce our exposure to volatile swings in crude oil prices and position us to effectively compete in the asphalt market. 5 During 2002, approximately 2,609 Bbls per day of our oil produced locally were used as feedstock, accounting for approximately 91% of the asphalt refinery throughput. Our properties also produce natural gas which is used to fuel the field production and the refinery, in part. We operate all of the wells associated with our Integrated Operations division. International Operations. Other than the Fengcheng Block in which we have a 49% operating working interest, we have a 60% operating working interest in five coalbed methane ("CBM") exploration and development projects within the Provinces of Jiangxi, Shanxi and Anhui, China. As of December 31, 2002, the Company had estimated net proved reserves of approximately 28,542 MBOE with a PV-10 value (10 year present value) before tax of $177.6 million. During 2002, the estimated net proved reserves increased over last year by 14,966 MBOE. Our principal offices are located at 630 Fifth Avenue, Suite 1501, New York, New York 10111 and our telephone number is (212) 218-4680. Business Strategy We intend to implement a two-pronged strategy: Capitalize on Our California Market Position. Our asphalt refinery, prior to 1992 was owned and operated for approximately fifty years by Conoco and ran between 9,000 to 11,000 Bbls per day of throughput. We expect that our refinery can attain its rated capacity of 10,000 Bbls per day of throughput. As of December 31, 2002, we utilized approximately 30% of this rated capacity. Our strategy in these vertically integrated assets is to enhance the long-term equity barrel feedstock supply to the refinery and to cost-efficiently boost production from the drilling locations identified in California. Our total average throughput currently at the asphalt refinery is approximately 3,000 Bbls per day, a 24% increase over 2001 levels. Approximately 90% of current throughput is now equity barrels. In our integrated business on a recurring basis, we are designed to be a relatively fixed cost operation with an established infrastructure in place. Equity production and throughput at the refinery increases ought to be realized without significant infrastructural costs to us. In this division, we are focused on organic production growth by returning to production the large inventory of shut-in wells acquired in recent acquisitions. Major oil companies, such as Union Oil Company, Shell and Texaco, began drilling in the Santa Maria, California basin in the early 1900's and built a consolidated infrastructure of pipelines and facilities. Thousands of wells were drilled discovering several productive oil and gas zones between 2,500 ft. and 8,500 ft. The shallower Sisquoc zone with heavier 6-12 gravity oil was passed over in favor of the deeper Monterey zone which was generally at a depth below 5,000 ft. and the lightest oil zone carrying the highest margins. Thus, the majors primarily concentrated on the Monterey zone and largely ignored the others. It is this enormous proven reserve base that provides a specific road map for the Company to build a substantial production base. Our objectives are to exploit through increased production both the gas reservoirs for fuel self-sufficiency and the oil for asphalt production. Pursue High Potential International Prospects on a Longer-Term Basis. GREKA is party to and operator under five, 30-year production sharing contracts ("PSCs") with China United Coalbed Methane Corporation Ltd. ("CUCBM") for CBM exploitation in China within two development and three exploration blocks. The combined total contract area within the Jiangxi, Shanxi and Anhui Provinces is approximately 6,600 square kilometers (1.7 million acres) with average coalbed thickness of 16.5 feet and potential reserves of 34.5 Tcf, as estimated by CUCBM. GREKA has a 60% working interest in all PSCs other than the Fengcheng Block in which it has a 49% working interest. The remaining working interest is owned by CUCBM. 6 Empowered by the State Council, CUCBM, a wholly state-owned company, is the only company responsible for exploration, development, production and sales of CBM in China. The signing of the four contracts brings the total number of CBM PSCs signed by CUCBM with foreign companies to 18, five of which are with GREKA. The total area covered by the 18 PSCs is over 31,000 sq km containing CBM resources of approximately 3.4 trillion m3 (120 Tcf) of which GREKA's PSCs are estimated at 30%, as estimated by CUCBM. Business Development of GREKA GREKA Energy Corporation was formed in 1988 as a Colorado corporation under the name of Kiwi III, Ltd. On May 13, 1996, GREKA, then known as Petro Union, Inc., filed a voluntary petition for relief pursuant to Chapter 11 of the United States Bankruptcy Code. Current GREKA management acquired Petro Union, Inc. and simultaneously procured on August 28, 1997, an order confirming Petro Union's First Amended Plan of Reorganization from the Bankruptcy Court for the Southern District of Indiana. The Bankruptcy Court approved the final accounting and closed the bankruptcy proceedings on March 26, 1998. During 1998, our management focused substantially all of its efforts on corporate restructuring, recapitalization and acquisition efforts and an investment in a horizontal drilling pilot program in the Cat Canyon field in California that all were part of implementing its strategic niche growth plan. During the latter part of 1998 and early 1999, management was primarily focused on the acquisition of Saba, which had substantial reserves suited to exploitation by GREKA's horizontal drilling technology, and considerable expenses were incurred in connection with the Saba transactions in the first quarter of 1999. On March 22, 1999, the Company, then known as Horizontal Ventures, Inc., changed its name to GREKA Energy Corporation. Effective March 24, 1999, GREKA acquired Saba Petroleum Company as a wholly owned subsidiary. Immediately subsequent to the completion of the Saba acquisition, management commenced its strategy to reverse the decline in value of the Saba assets which included securing bank financing of up to $47.0 million, reducing Saba debt by $27.2 million, assuming full operation of our asphalt refinery, which increased operating cash flows, selling non-core assets in Colombia (the "Columbian assets") while maintaining a repurchase option, acquiring all of the shares we did not already own of Beaver Lake Resources Corporation, and signing a production sharing contract with CUCBM to jointly exploit CBM resources in China. During December 1999, GREKA commenced trading on the Nasdaq National Market System. During 2000, management exercised GREKA's option to repurchase the Colombian assets, closed the financing with a new bank, Canadian Imperial Bank of Commerce, of up to $47.5 million with a portion of the proceeds used to reduce current debt resulting in the complete elimination of Saba's defaulted bank debt, completed the sale of all our non-core assets in Canada, settled with Capco Resources, Ltd. and its related parties whereby GREKA cancelled 840,000 shares of its common stock for $5.2 million and gained voting control over the remaining 514,500 shares owned by Capco, declared a payment of a 5% stock dividend to our shareholders of record at close of market on December 31, 2000, and completed a spot secondary public offering of 542,785 shares (including over-allotment option) at a price of $13.10 per share. During 2001, GREKA increased up to $46 million its credit facility with GMAC Commercial Credit LLC ("GMAC") and secured financing of up to $75 million with a new bank, Bank of Texas, N.A., closing on a revolving credit line of $16 million with an initial advance of $13.2 million. Later that year, the Company announced a repurchase program to buy back up to 10% of its outstanding common stock. Also in 2001, GREKA concluded the Colombian transaction resulting in its receipt of cash and assets with an aggregate value of $14 million, and, operationally, GREKA announced exploration success at the Potash Field with the drilling of its HD No. 1 well with initial production at over 6 MMCF per day. By the end of the year, GREKA concluded all material legal matters, including payment of $11.5 million to RGC International Investors for settlement in full of a court order awarding RGC $13.25 million. 7 Year 2002 Highlights o In March 2002, the Company announced that it intended to substantially restructure its operations by disposing of its exploration and production assets which had been operated through its E&P Americas subsidiary and to focus on its Integrated Operations around its asphalt refinery located in Santa Maria, California. At the end of May 2002, we closed the sale of the most substantial portion of the E&P Americas' assets, the Potash Field located in South Louisiana for $20 million, the proceeds of which were used to pay debt, which included $12.5 million to the Bank of Texas, N.A. The sale of the Potash Field essentially completed the divestiture of the Company's E&P Americas' assets. In June 2002, we concluded a refinancing of our debt by closing a $30 million secured credit facility through Guggenheim Investment Management, LLC. The proceeds of this credit facility were used to payoff the $14.3 million GMAC term loan, $12 million to purchase of the Vintage Petroleum, Inc. ("Vintage") properties in the Santa Maria Valley and the balance toward working capital and closing expenses. Also in June 2002, to complete the purchase of the Santa Maria Valley properties, we executed a promissory note for the remaining $6 million purchase price owed to Vintage to be paid within twelve months. In July 2002, we closed as planned our Houston office following the E&P asset divestitures. o As a result of the completed restructuring, substantially all of our oil, gas and refining assets and operations are located within a 20 mile radius in the Santa Maria Valley of California. As part of our restructuring strategy, we focused on boosting production of our heavy crude to increase the feedstock of our equity oil for use in our Santa Maria Refinery. The closing of the Vintage acquisition increased equity oil production. o In September 2002, we sold real estate for a contract price of $2.325 million, and we paid $1.1 million toward the $5.1 million bridge facility that closed in the second quarter of 2002. The payment was made from the sale proceeds of certain real estate owned by the Company. Also as of September 2002, we satisfied in full our 15% subordinated convertible debentures by converting $1.26 million in principal plus accrued interest into 251,348 shares of GREKA common stock and paying $0.26 million in principal plus accrued interest that had been redeemed. o In October 2002, the $4 million balance of the $5.1 million bridge facility was transferred to International Publishing Holding, Inc. ("IPH"), and IPH cancelled the irrevocable standby letter of credit in the amount of $4 million that was arranged in favor of the initial creditor. o Also in October 2002, we acquired Rincon Island Limited Partnership ("Rincon"), and its general partner, Windsor Energy US Corporation ("Windsor"), that owns and operates oil and gas producing properties and facilities located within the Rincon Island Field in central California. The properties cover approximately 1,700 mineral acres, including a 1-acre island connected to land by a 2,700' causeway containing the gas and oil pipelines and facilitating vehicular access. In October 2002, of the 56 wells on the property, 12 were producing at approximately 300 BOPD and 80 MCFD. Substantial value of the field lies in the large, proved undeveloped portion and in the partially exploited secondary recovery reserves of non-flooded zones where production historically peaked at approximately 2,500 BOPD and 1.5 MMCFD. Additionally, there are 21 slots available on the island providing the foundation for the development of the substantial reserves. 8 o Further in October 2002, we restructured some of our debt and increased working capital by institutionally placing $12.5 million of secured debt, which accretes up to $14.5 million until maturity. Of the $12.5 million proceeds, we paid off our outstanding debt to Vintage and all but approximately $832,000 of our convertible debentures, acquired $5.35 million worth of operational bonds related to the acquisition of Rincon and Windsor, and applied the balance toward working capital and closing costs. o Lastly in October 2002, we entered into an amendment to our 30-year production sharing contract with the CUCBM to extend for an additional two years through December 2004 the term in which core testing is to be conducted and the pilot program is to be developed in our Fengcheng Coalbed Methane Exploration Prospect in Jiangxi, China. Acquisition Activities; California Integrated Assets In June 2002, we closed, as scheduled, the acquisition of all of Vintage's oil and gas producing properties and facilities in the Santa Maria Valley of central California for $18 million. These properties, operated by the Company, consist of five fields and approximately 110 producing wells, encompassing approximately 8,000 acres of mineral interest and over 800 acres of real estate. In October 2002, we acquired Rincon, and its general partner, Windsor, that owns and operates oil and gas producing properties and facilities located within the Rincon Island Field in central California. The properties cover approximately 1,700 mineral acres, including a 1-acre island connected to land by a 2,700' causeway containing the gas and oil pipelines and facilitating vehicular access. At closing, of the 56 wells on the property, 12 were producing at approximately 300 BOPD and 80 MCFD. Divestiture Activities; Non-Core Assets In April 2002, we sold, as planned, our interest in the Manila Village Field located in Jefferson Parish, south Louisiana for approximately $55,000. In May 2002, we closed, as planned, the sale of our interest in the Potash Field, Plaquemines Parish, Louisiana for a contract price of approximately $20 million. In June 2002, we closed, as planned, the sale of our 75% exploration interest in the Jatiluhur Block, West Java for a $4 million future production payment upon discovery of reserves producible in commercial quantities and a retained 5% overriding royalty interest in the Block. Pertamina, the Indonesian state-owned oil company, consented to the sale. In September 2002, we sold real estate for a contract price of approximately $2.3 million. In January 2003, we closed, as planned, the sale of our 355-acre limestone reserve located in Monroe County, Indiana for a contract price of $0.5 million. Financing & Debt Restructuring Activities In April 2002, we closed a $5.1 million bridge facility to provide short-term liquidity during the implementation of GREKA's restructuring. In April 2002, we paid in full the loan obligation in the principal amount of $2.4 million to IPH, thereby releasing collateral of all issued and outstanding shares of capital stock of a GREKA subsidiary. In May 2002, Bank of Texas, N.A. was paid $12.5 million from the proceeds of the closed sale of our interest in the Potash Field. 9 In June 2002, we institutionally placed $30 million of a secured credit facility to conclude the Company's debt restructuring and to close the acquisition of the Santa Maria Valley oil and gas assets. Of these proceeds, we paid $14.3 million to GMAC to retire its term loan and $12 million to Vintage. Also in June 2002, we executed a promissory note for the remaining $6 million purchase price owed to Vintage to be paid within twelve months. In September 2002, we paid $1.1 million toward the $5.1 million bridge facility that closed in the second quarter 2002. The payment was made from the sale proceeds of certain real estate owned by the Company. In October 2002, the $4 million balance of the $5.1 million bridge facility was transferred to IPH, and IPH cancelled the irrevocable standby letter of credit in the amount of $4 million that was arranged in favor of the initial creditor. Also in October 2002, we restructured some of our debt and increased working capital by institutionally placing $12.5 million of secured debt, which accretes up to $14.5 million until maturity. Of the $12.5 million proceeds, we paid off our outstanding debt to Vintage and all but approximately $832,000 of our convertible debentures, acquired $5.35 million worth of operational bonds related to the acquisition of Rincon and Windsor, and applied the balance toward working capital and closing costs. In March 2003, our placed $20 million with an institutional investor through a 2-year, secured credit facility. From these proceeds, the Company paid $4.7 million to Bank of Texas and $4.1 million to IPH to retire their respective loans, and the balance, in addition to closing costs and working capital, will fund a portion of the Company's $15 million capital expenditure program for 2003. Of the $20 million, $13.5 million bears interest at a variable rate of Libor + 6.25% or 8.25%, whichever is greater, while the balance $6.5 million bears interest at a fixed rate of 9.25%. The Company paid a 4.25% closing fee, and the placement resulted in an increase of approximately $10 million of the Company's total debt. Debentures As of September 2002, we satisfied, in full, its 15% subordinated convertible debentures by converting $1.26 million in principal plus accrued interest into 251,348 shares of GREKA common stock and paying $0.26 million in principal plus accrued interest that had been redeemed. During 2002, GREKA converted $0.04 million in principal of its 9% senior subordinated convertible debentures into 4,118 shares of GREKA common stock and paid $1.74 million in principal of debentures that had been redeemed, with a resulting debenture balance of $0.83 million in principal at December 31, 2002. GREKA's Horizontal Drilling Technology Horizontal drilling has become widely accepted as a standard option for exploiting oil & gas resources. The principal advantage of horizontal drilling is that it results in a substantially greater surface area for drainage, and thus extraction of the oil from the reservoir. In industry terms this is referred to as communicating zones of permeability. The unique method of re-entering a well and horizontal drilling patented by BP Amoco and licensed to GREKA allows for turning while drilling, which can cause a vertical well to be horizontal in as little as 25 feet. Thus this technology provides considerable flexibility to the geologists and engineers in designing their well plans around geological formation and reservoir constraints to achieve maximum performance. Furthermore, this technique facilitates multi-laterals off an existing well bore, which avoids costly drilling of new wells, and has considerable advantages in shallow reservoirs where the traditional horizontal tools cannot be utilized due to their larger radius requirements and related economics. 10 Marketing Marketing of Asphalt Refinery Production Our asphalt refinery in Santa Maria, California produces light naphtha, kerosene distillate, gas oils and numerous cut-back, paving and emulsion asphalt products. Historically, we have focused marketing efforts on the asphalt products which are sold to various users, primarily in the Central and Northern California areas. Distillates are readily marketed to wholesale purchasers. Four customers exceeded individually more than 10 percent of the Company's sales of North American refinery production during 2002, namely FAMM, Lawson, Union and Granite which accounted for approximately 18%, 20%, 20% and 18%, respectively, of such sales. The receivable balance as of December 31, 2002 from the same customers amounted to $97,757, $848,237, $217,252 and $265,808, respectively. GREKA regards the refinery as a valuable adjunct to its production of crude oil in the Santa Maria Valley and surrounding areas. Generally, the crude oil produced in these areas is of low gravity and makes an excellent asphalt. Prices for asphalt exceed market prices for crude and costs of operating the refinery. GREKA believes that as road building and repairs increase in California and surrounding western states, the market for asphalt will expand significantly. We market two principal products from our refinery: liquid asphalt and light-end products (gas oil, naphtha and distillates). Liquid asphalt, which accounted for approximately 60% of total refinery production in 2002, is marketed primarily in California. While liquid asphalt is principally used for road paving and manufacturing roofing products, all of the liquid asphalt sold by GREKA's subsidiary is used for pavement applications. Paving grade liquid asphalt is sold by GREKA's subsidiary to hot mix asphalt producers, material supply companies, contractors and government agencies. These customers further treat the liquid asphalt which is used for road paving. In addition to conventional paving grade asphalt, our subsidiary can also produce modified and cutback asphalt products. Modified asphalt is a blend of recycled plastics, rubber and polymer materials with liquid asphalt, which produces a more durable product that can withstand greater changes in temperature. Cutback asphalt is a blend of liquid asphalt and lighter petroleum products and is used primarily to repair asphalt road surfaces. Additionally, some of the paving grade and modified asphalts we produce are sold as base stocks for emulsified asphalt products that are primarily used for pavement maintenance. Because the chemical footprint unique to the heavy crude oil indigenous to the Santa Maria Valley readily blends, we are particularly well positioned to supply the asphalt specifications in accordance with the standards established by the National Highway and Transportation Administrations Strategic Highway Research Program (SHRP) or set by the American Association of State Highway and Transportation Officials. Demand for liquid paving asphalt products is primarily affected by federal, state and local highway spending, as well as the general state of the California economy, which drives commercial construction. Another factor is weather, as asphalt paving projects are usually shut down in cold, wet weather conditions. All of these demand factors are beyond our control. Government highway spending provides a source of demand which has been relatively unaffected by normal business cycles but is dependent on appropriations. Growth in the California economy is generally good for the Company, as increased business activity results in increased construction activity, including new road construction and repair efforts on existing roads in both the public and private sectors. A slowing economy could negatively impact both sales and pricing of products. As our asphalt refinery and principal markets are located in California, the following discussion focuses on government highway funds available in California. 11 Federal Funding Federal funding of highway projects is accomplished through the Federal Aid Highway Program. The Federal Aid Highway Program is a federally-assisted, state-administered program that distributes federal funds to the states to construct and improve urban and rural highway systems. The program is administered by the Federal Highway Administration (FHWA), an agency of the Department of Transportation. Nearly all federal highway funds are derived from gasoline user taxes assessed at the pump. In June 1998, the $217 billion federal highway bill, officially known as the Transportation Equity Act for the 21st Century or TEA-21 was enacted. The bill is estimated to increase transportation-related expenditures by $850 million a year in California alone over a six fiscal year period beginning October 1, 1997. This will equate to a 51% increase over previous funding levels. The average California apportionment over the six year period ending in October 2003 is estimated to be $2.50 billion per year or a total of $15 billion. However, while management of one of GREKA's subsidiaries believes it has benefited from and should benefit in the future from such funding increases, there can be no guarantee that it will in fact do so in the future. State and Local Funding In addition to federal funding for highway projects, states individually fund transportation improvements with the proceeds of a variety of gasoline and other taxes. In California, the California Department of Transportation (CALTRANS) administers state expenditures for highway projects. According to the Department of Finance for the State of California, funding available from the State Highway Account is estimated to average $1.13 billion per year over the next 10 years excluding the Seismic Retrofit Bond Fund. This compares to an average of $0.36 billion over the previous ten years. Marketing of our Oil and Gas Production The prices obtained for oil and gas are dependent on numerous factors beyond our control, including domestic and foreign production rates of oil and gas, market demand and the effect of governmental regulations and incentives. A portion of our North American crude oil production is sold at the wellhead at posted prices under short term contracts, as is customary in the industry. Other than production from the Company's Integrated Operations Division which is transported to our refinery, three customers exceeded individually more than 10 percent of the Company's sales of North American oil and gas production during 2002, namely Tosco, Adams Resources and Plains Marketing, L.P. which accounted for 51%, 12% and 15%, respectively, of such sales. Sales to Adams Resources and Plains Marketing, L.P. were from properties subsequently sold. The market for heavy crude oil produced by GREKA from properties in central California differs substantially from the remaining domestic crude oil market, due principally to GREKA's sale to the market of asphalt, naphtha and distillates rather than hydrocarbons. GREKA's Santa Maria refinery uses essentially all of its central California crude oil, in addition to third party crude oil, to produce asphalt, among other products. Ownership and operation of the refinery gives us a steady and stable market for its local crude oil which is not enjoyed by other producers. Competition Competition in the oil and gas business is intense, particularly with respect to the acquisition of producing properties, proved undeveloped acreage and leases. Major and independent oil and gas companies actively bid for desirable oil and gas properties and for the equipment and labor required for their operation and development. We believe that the locations of our leasehold acreage, our exploration, drilling and production capabilities and the experience of our management and that of our industry partners generally enable us to compete effectively. Many of our competitors, however, have financial 12 resources and exploration, development and acquisition budgets that are substantially greater than ours, and these may adversely affect GREKA's ability to compete, particularly in regions outside of GREKA's principal producing areas. Because of this competition, GREKA cannot assure that it will be successful in finding and acquiring producing properties and development and exploration prospects. Our management believes we have an advantage over our competition in the regional asphalt market within central California because of our vertical integration and self-sufficiency in our Integrated Operations Division, resulting in margins higher than other refiners in the same market. Governmental Regulation The following discussion of regulation of the oil and gas industry is necessarily brief and is not intended to constitute a complete discussion of the various statutes, rules, regulations or governmental orders to which operations of GREKA and its subsidiaries may be subject. Federal Regulation of First Sales and Transportation of Natural Gas The sale and transportation of natural gas production from properties owned by our subsidiaries may be subject to regulation under various federal and state laws including, but not limited to, the Natural Gas Act ("NGA") and the Natural Gas Policy Act ("NGPA"), both of which are administered by the Federal Energy Regulatory Commission ("FERC"). The provisions of these acts and regulations are complex. Under these acts, producers and marketers have been required to obtain certificates from FERC to make sales, as well as obtaining abandonment approval from FERC to discontinue sales. Additionally, first sales have been subject to maximum lawful price regulation. However, the NGPA provided for phased-in deregulation of most new gas production and, as a result of the enactment on July 26, 1989 of the Natural Gas Wellhead Decontrol Act of 1989, the remaining regulations imposed by the NGA and the NGPA with respect to "first sales" were terminated by no later than January 1, 1993. FERC jurisdiction over transportation and sales other than "first sales" has not been affected. Because of current market conditions, many producers, including GREKA, are receiving contract prices substantially below most remaining maximum lawful prices under the NGPA. Our management believes that most of the gas to be produced from GREKA's properties is already price-deregulated. The price at which such gas may be sold will continue to be affected by a number of factors, including the price of alternate fuels such as oil. At present, two factors affecting prices are gas-to-gas competition among various gas marketers and storage of natural gas. Moreover, the actual prices realized under GREKA's current gas sales contracts also may be affected by the nature of the decontrolled price provisions included therein and whether any indefinite price escalation clauses in such contracts have been triggered by federal decontrol. The economic impact on GREKA and gas producers generally of price decontrol is uncertain, but it currently appears to be resulting in higher gas prices. Currently, there is a shortage of deliverable gas in most areas of the United States and, accordingly, it remains possible that gas prices may remain at relatively high levels. This is in sharp contrast to even recent pricing which has been depressed for some time since deregulation. Producers such as GREKA or resellers may be required to reduce prices in the future in order to assure continued sales. It is also possible that gas production from certain properties may be shut-in altogether for lack of an available market. Commencing in the mid-1980's, FERC promulgated several orders designed to correct market distortions and to make gas markets more competitive by removing the transportation barriers to market access. These orders have had a profound influence upon natural gas markets in the United States and have, among other things, fostered the development of a large spot market for gas. The following is a brief description of the most significant of those orders and is not intended to constitute a complete description of those orders or their impact. 13 On April 8, 1992, FERC issued Order 636, which is intended to restructure both the sales and transportation services provided by interstate natural gas pipelines. The purpose of Order 636 is to improve the competitive structure of the pipeline industry and maximize consumer benefits from the competitive wellhead gas market. The major function of Order 636 is to assure that the services non-pipeline companies can obtain from pipelines is comparable to the services pipeline companies offer to their gas sales customers. One of the key features of the Order is the "unbundling" of services that pipelines offer their customers. This means that pipelines must offer transportation and other services separately from the sale of gas. The Order is complex and faces potential challenges in court. GREKA is not able to predict the effect the Order might have on its business. FERC regulates the rates and services of "natural-gas companies", which the NGA defines as persons engaged in the transportation of gas in interstate commerce for resale. As previously discussed, the regulation of producers under the NGA is being gradually phased out. Interstate pipelines, however, continue to be regulated by FERC under the NGA. Various state commissions also regulate the rates and services of pipelines whose operations are purely intrastate in nature, although generally sales to and transportation on behalf of other pipelines or industrial end-users are not subject to material state regulation. There are many legislative proposals pending in Congress and in the legislatures of various states that, if enacted, might significantly affect the petroleum industry. It is impossible to predict what proposals will be enacted and what effect, if any, such proposals would have on GREKA and its subsidiaries. State and Local Regulation of Drilling and Production State regulatory authorities have established rules and regulations requiring permits for drilling, drilling bonds and reports concerning operations. The states in which GREKA'S subsidiaries operate also have statutes and regulations governing a number of environmental and conservation matters, including the unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. A few states also pro-rate production to the market demand for oil and gas. Environmental Regulations Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, prohibit drilling activities on certain lands lying within wilderness and other protected areas and impose substantial liabilities for pollution resulting from drilling operations. Such laws and regulations may also restrict air or other pollution resulting from GREKA's operations. Moreover, many commentators believe that the state and federal environmental laws and regulations will become more stringent in the future. For instance, proposed legislation amending the federal Resource Conservation and Recovery Act would reclassify oil and gas production wastes as "hazardous waste". If such legislation were to pass, it could have a significant impact on the operating costs of GREKA, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, including states in which our subsidiaries have operations, and these various initiatives could have a similar impact on GREKA. Operational Hazards and Insurance GREKA's subsidiaries' operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. 14 GREKA's insurance does not cover every potential risk associated with the drilling, production and processing of oil and gas. In particular, coverage is not obtainable for certain types of environmental hazards. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on GREKA's financial condition and results of operations. Moreover, no assurance can be given that GREKA will be able to maintain adequate insurance in the future at rates it considers reasonable. GREKA and its subsidiaries have up to $11 million of general liability insurance. Additionally, GREKA and its subsidiaries have up to $10 million of environmental coverage through June 2007 covering the central California properties acquired in June 2002. The policy protects us against third party claims resulting from unknown pre-existing or new pollution conditions that cause on or offsite bodily injury, property damage or clean up. The policy also covers costs that exceed the projected costs for remediation of the known conditions on the properties. In addition to insurance coverage, bonds in the approximate principal amount of $6.8 million have been issued securing the operational performance of GREKA's subsidiaries in California. Employees As of March 17, 2003, GREKA and its subsidiaries had 126 full-time employees. None of GREKA's employees are subject to a collective bargaining agreement. GREKA considers its relations with its employees to be satisfactory. Shareholder Rights Plan We have a shareholder rights plan in order to preserve the long-term value of the Company for GREKA's shareholders. Under the shareholder rights plan, one right will be distributed for each outstanding share of GREKA common stock. Each right will entitle the holder to buy one share of GREKA common stock for an initial exercise price of $57.14 per share. The rights will initially trade with common shares and will not be exercisable unless certain takeover events occur. The plan generally provides that if a person or group acquires or announces a tender offer for the acquisition of 9.9% or more of GREKA common stock without approval of the Board of Directors, the rights will become exercisable and the holders of the rights, other than the acquiring person or group, will be entitled to purchase shares of GREKA common stock (or under certain circumstances stock of the acquiring entity) for 50% of its current market price. The rights may be redeemed by GREKA for a redemption price of $.01 per right. Retirement Plan The Company sponsors a defined contribution retirement savings plan ("401(k) Plan") to assist all eligible U.S. employees in providing for retirement or other future financial needs. We currently provide matching contributions equal to 50% of each employee's contribution, subject to a maximum of 8% of their eligible contribution. Net Profit Sharing Plan The Company has a net profit sharing plan ("NPSP") for employees that fulfill certain qualification requirements. The NPSP provides for an equal disbursement normally of 10% of the Company's pretax income, excluding extraordinary gains. Such disbursement is planned to follow the filing of the annual audited financial statements of the Company. However, the NPSP could be suspended, increased or otherwise amended at the discretion of the Board of Directors for any specific year. 15 Item 2. Description of Property The following description of the GREKA properties at December 31, 2002 includes all discussions of prior operations of all of GREKA's properties and those of its wholly owned subsidiaries. GREKA's Properties as of December 31, 2002 GREKA owned interests in approximately 1,200 wells at December 31, 2002. The majority of these wells are concentrated in central California. At December 31, 2002, California (heavy oil) was the primary and focused area of GREKA's exploitation and development activities. GREKA's evaluation of international exploration and exploitation project is in China. The Company continuously evaluates the profitability of its oil, gas and related activities and, as part of its strategic business plan, intends to divest unprofitable leases or areas of operations that are not consistent with its business strategy. Exploitation and Development Activities The following is a brief discussion of significant developments in California in the Company's recent exploitation and development activities through its wholly owned subsidiaries: Approximately 99% of GREKA's proved reserves at December 31, 2002 (28.2 MMBOE) were located in four regions in California. Daily production from these regions averaged 3,300 BOE (gross) for the year ended December 31, 2002, representing 99% of GREKA's total production. GREKA operates all of its wells in these California regions. The remaining 1% of GREKA's proved reserves at December 31, 2002 is allocated to domestic producing properties in which GREKA has an interest located in four states other than California. GREKA seeks to acquire domestic and international producing properties where it can significantly increase reserves through development or exploitation activities and control costs by serving as operator. GREKA believes that its substantial experience and established relationships in the oil and gas industry enable it to identify, evaluate and acquire high potential properties on favorable terms. As the market for acquisitions has become more competitive in recent years, GREKA has taken the initiative in creating acquisition opportunities, particularly with respect to adjacent properties, by directly soliciting fee owners, as well as working and royalty interest holders, who have not placed their properties on the market. GREKA's 2003 discretionary capital expenditure budget for properties is dependent upon the price for which its products are sold and upon the ability of GREKA to obtain external financing. Subject to these variables and based on the current asset base, we expect our cash flow and credit facilities to fund approximately $15 million in 2003 for capital expenditure. (See Item 1 - "Description of Business, Financing & Debt Restructuring Activities") The Company's 2003 capex program is designed to facilitate organic production increases from the integrated operations. Capex projects identified for 2003, namely workovers, redrills, recompletions, side-tracks, and various facility enhancements, are scheduled throughout the year. Exploration Activities GREKA further plans to expand its existing reserve base by developing high potential exploration prospects in known productive regions. GREKA believes these activities complement its traditional development and exploitation activities. In pursuing these exploration opportunities, GREKA may use advanced technologies, including 3-D seismic and satellite imaging. In addition, GREKA may seek to limit its direct financial exposure in exploration projects by entering into strategic partnerships that shift the drilling related financial risks to partners while providing the Company with an upside upon a successful event. At December 31, 2002, GREKA had exploration plays in two primary areas: California and China. 16 The following is a brief discussion of significant developments in the Company's recent exploration activities through its wholly owned subsidiaries: Coalinga Nose Exploration Prospect, Fresno County, California. GREKA has leases and contractual rights covering approximately 9,000 acres of land in the region of the prolific Coalinga oil field in the San Joaquin Valley of California. GREKA participated in a 16 square mile 3-D seismic survey covering this area and has interpreted the survey. Nineteen anomalies have been identified in the prospect area, covering five potentially productive zones, ranging in depth from 6,500 to 12,000 feet. GREKA has an 89% working interest below and a 9% working interest above the Gatchell formation in the Leda Prospect, Pleasant Valley, and Cotton Gin Prospects. Since December 31, 2002, GREKA re-evaluated the potential productive zones within the field and identified the most prospective areas. The Company intends to reduce its acreage in the field to these identified areas. Coalbed Methane Exploration Prospect, Jiangxi, Shanxi and Anhui Provinces, China. In January 2003, GREKA's wholly-owned subsidiaries signed at the Great Hall of the People in China four Production Sharing Contracts PSCs with CUCBM for the exploitation of CBM resources in the Shanxi and Anhui Provinces. Considering the previously signed PSC for the Fengcheng Block in the Jiangxi Province, GREKA is now party to and operator under five, 30-year PSCs for CBM exploitation in China within two development and three exploration blocks. The combined total contract area is approximately 6,600 square kilometers (1.7 million acres) with average coalbed thickness of 16.5 feet and potential reserves of 34.5 Tcf, as estimated by CUCBM. Greka has a 60% working interest in all PSC's other than the Fengcheng Block in which it has a 49% working interest. The remaining working interest is owned by CUCBM. Oil and Gas Producing Properties The following table summarizes GREKA's estimated proved oil and gas reserves as of December 31, 2002. The following table includes both proved developed (producing and non-producing) and proved undeveloped reserves. Approximately 51% of the total reserves reflected in the following table are proved undeveloped. There can be no assurance that the timing of drilling, reworking and other operations, volumes, prices and costs employed by Netherland Sewell & Associates and/or Ryder-Scott Company Petroleum Consultants, independent petroleum engineers, will prove accurate. Since December 31, 2002, oil and gas prices have generally increased. At such date, the price of WTI crude oil as quoted on the New York Mercantile Exchange was $29.39 per Bbl and the comparable price for March 17, 2003 was $34.93. Quotations for the comparable periods for natural gas were $4.84 per Mcf and $5.51 per Mcf, respectively. The proved developed and proved undeveloped oil and gas reserve figures are estimates based on reserve reports prepared by GREKA's independent petroleum engineers Netherland Sewell & Associates and Ryder-Scott Company Petroleum Consultants. The estimation of reserves requires substantial judgment on the part of the petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Estimates of reserves and of future net revenues prepared by different petroleum engineers may vary substantially, depending, in part, on the assumptions made, and may be subject to material adjustment. Estimates of proved undeveloped reserves comprise a substantial portion of GREKA's reserves and, by definition, had not been developed at the time of the engineering estimate. The accuracy of any reserve estimate depends on the quality of available data as well as engineering and geological interpretation and judgment. Results of drilling, testing and production or price changes subsequent to the date of the estimate may result in changes to such estimates. The estimates of future net revenues in this report reflect oil and gas prices and production costs as of the date of estimation, without escalation, except where changes in prices were fixed under existing contracts. There can be no assurance that such prices will be realized or that the estimated production volumes will be produced during the periods specified in such reports. The estimated reserves and future net revenues may be subject to material downward or upward revision based upon production history, results of future development, prevailing oil and gas prices and other factors. A material decrease in estimated reserves or future net revenues could have a material adverse effect on GREKA and its operations. 17 December 31, 2002 Proved Reserves, net Gross Oil Gas PV-10 Value Wells (MBbls) (MMcf) MBOE (000's) ----- ------- ------ ------ ------------ 322 26,571 11,822 28,542 $177,584 The following is a brief discussion of our oil and gas operations in our major fields located in California at December 31, 2002: Central Coast Fields. One of GREKA's subsidiaries operates seven fields in the Central Coast area of California. These fields provide equity crude oil for GREKA's wholly owned asphalt refinery. The fields are Cat Canyon, Casmalia, Gato Ridge, Santa Maria Valley, Zaca, Clark Avenue and Los Flores which collectively have an average working interest of 100% in 179 active wells producing 2,364 BOEPD (gross). These fields represent 38% of GREKA's total proved reserves. North Belridge Field. The North Belridge Field is located in Kern County, California. One of GREKA's subsidiaries is the operator and owns 100% working interest in 42 wells on three leases covering 270 contiguous acres. The wells produce from two formations-- light oil from the Diatomite zone and heavy oil from the Tulare formation. Production is about 300 BOEPD, and this field represents 8% of GREKA's total proved reserves. Rincon Field. One of GREKA's subsidiaries operates the Rincon Field which is located in the Central Coast of California and covers approximately 1,700 mineral acres, including a 1-acre island connected to land by a 2,700' causeway containing the gas and oil pipelines and facilitating vehicular access. GREKA has a 100% working interest in 16 active wells producing approximately 371 BOEPD. This field represents 40% of the Company's total reserve value. Richfield East Dome Unit. The Richfield East Dome Unit is a mature waterflood (one method of secondary recovery in which water is injected into an oil reservoir for the purpose of washing the oil out of the reservoir rock into the bore of a producing well) in Orange County, California, operated by one of GREKA's subsidiaries and producing approximately 615 BOPD from 94 active wells. The field in which GREKA's working interest is 99%, represents 12% of the Company's total reserve value. Waterflood operations were initiated in 1974 by Texaco. Field facilities are in sufficiently satisfactory condition to service the waterflood operation through the remaining life of the field. Oil and Gas Reserves Our proved reserves and the estimated present value of future revenues from proved developed and undeveloped oil and gas properties in this document have been estimated by our independent petroleum engineers. In 2000, 2001 and 2002, Netherland, Sewell & Associates, Inc. prepared reports on GREKA's reserves in the United States (except in the Rincon Field, California), and in 2002 Ryder-Scott Company Petroleum Consultants prepared reports on GREKA's reserves in the Rincon Field, California. The estimates of these independent petroleum engineers were based upon review of production histories and other geological, economic, ownership and engineering data provided by GREKA. In accordance with the SEC's guidelines, GREKA's estimates of future net revenues from GREKA's proved reserves and the present value thereof are made using oil and gas sales prices in effect as of year end and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalation. Future gross revenues at December 31, 2002 reflect weighted average prices of $23.07 per BOE compared to $14.53 per BOE and $26.93 per BOE as of December 31, 2001 and 2000, respectively. 18 The following tables present total estimated proved developed producing, proved developed non-producing and proved undeveloped reserve volumes as of December 31, 2000, 2001 and 2002 and the estimated present value of future net revenues ("PV-10") (based on current prices and costs at the respective year's end, using a discount factor of 10 percent per annum). As used herein, the term "proved undeveloped reserves" are those which can be expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. We do not include estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. There can be no assurance that these estimates are accurate predictions of reserves or of future net revenues from oil and gas reserves or their present value. The prices received for oil and gas have generally increased since the preparation of the 2002 year end engineering estimates. Estimated Proved Oil and Gas Reserves At December 31, --------------------------- 2000(1) 2001(1) 2002 ------- ------- ------- Net oil reserves (MBbl) Proved developed producing .............. 7,059 4,310 11,672 Proved developed non-producing .......... 1,309 2,664 1,839 Proved undeveloped ...................... 3,644 3,078 13,060 ------ ------ ------ Total proved oil reserves (MBbl) ....... 12,012 10,052 26,571 ====== ====== ====== Net natural gas reserves (MMcf) Proved developed producing .............. 5,184 2,206 1,929 Proved developed non-producing .......... 4,758 5,822 453 Proved undeveloped ...................... 10,133 11,354 9,440 ------ ------ ------ Total proved natural gas reserves (MMcf) ..................... 20,075 19,382 11,822 ====== ====== ====== Total proved reserves (MBOE) ............... 15,662 13,576 28,542 ====== ====== ====== ---------- (1) Does include reserve volumes attributable to the Company's interest in assets subsequently divested. Estimates of proved reserves may vary from year to year reflecting changes in the price of oil and gas and results of drilling activities during the intervening period. Reserves previously classified as proved undeveloped may be completely removed from the proved reserves classification in a subsequent year as a consequence of negative results from additional drilling or product price declines which make such undeveloped reserves non-economic to develop. Conversely, successful development and/or increases in product prices may result in additions to proved undeveloped reserves. 19 Estimated Present Value of Future Net Revenue (In thousands) At December 31, ------------------------------ 2000(1) 2001(1) 2002 -------- -------- -------- PV-10 Value Proved developed producing .......... $ 67,080 $15,180 $60,022 Proved developed non-producing ...... 37,160 21,164 13,615 Proved undeveloped .................. 59,637 20,274 103,947 -------- -------- -------- Total ............................ $163,877 $56,618 $177,584 ======== ======== ======== ---------- (1) Does include value attributable to the Company's interest in assets subsequently divested. As used herein, the terms "proved oil and gas reserves," "proved developed oil and gas reserves," and "proved undeveloped reserves" have the meanings defined by the SEC as set forth in the Table of Contents to this document. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports contained herein. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. The following table summarizes sales volume, sales price and production cost information for GREKA's net oil and gas production for each of the years in the three-year period ended December 31, 2002. Year Ended December 31, -------------------------- 2000(1) 2001(1) 2002 ------- ------- ------ Production Data: Oil (MBbls) .................... 770 827 1,021 Gas (MMcf) ..................... 1,807 1,848 371 Total (MBOE) ................. 1,099 1,163 1,083 Average Sales Price Data (Per Unit): BOE ............................ $22.14 $19.51 $21.89 Selected Data per BOE: Production costs(2) ............ $ 5.51 $ 7.87 $ 4.90 General and administrative ............... $ 5.79 $ 3.22 $ 3.43 Depletion, depreciation and amortization ................. $ 2.90 $ 4.34 $ 3.12 ---------- (1) Does include sales volumes attributable to the Company's interest in assets subsequently divested. (2) Production costs include production taxes. 20 Drilling Activity With respect to GREKA's participation in the drilling of exploratory and development wells for each of the three years in the three year period ended December 31, 2002, there has been no drilling activity except as set forth in the following table: Year Ended December 31, --------------------------------------------------------- 2000 2001 2002 ----------------- ----------------- ----------------- Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) -------- ------ -------- ------ -------- ------ United States: Development Wells Oil 5 5 1 1 -- -- Gas -- -- 1 1 -- -- Dry (3) 1 1 -- -- -- -- ---------- (1) A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. (2) A net well is deemed to exist when the sum of fractional ownership working interest in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. (3) A dry hole is an exploratory or development well that is not a producing well. Productive Oil and Gas Wells The following table sets forth information at December 31, 2002, relating to the number of productive oil and gas wells (producing wells and wells capable of production, including wells that are shut in) in which GREKA through its subsidiaries owned a working interest in the United States: Oil Gas Total Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- 2002 280 272 42 39 322 311 2001 498 450 25 9 523 459 2000 625 487 80 41 705 528 Oil and Gas Acreage The following table sets forth certain information at December 31, 2002 relating to oil and gas acreage in the United States in which GREKA through its subsidiaries owned a working interest: Developed(1) Undeveloped --------------- -------------- Gross Net Gross Net ----- --- ----- --- 2002 13,693 10,515 11,201 8,025 2001 21,070 16,180 11,201 8,025 2000 21,070 16,180 11,201 8,025 ---------- (1) Developed acreage is acreage assigned to productive wells. 21 Title to Properties Many of GREKA's subsidiaries' oil and gas properties are held in the form of mineral leases, licenses, reservations, concession agreements and similar agreements. In general, these agreements do not convey a fee simple title to GREKA, but rather, depending upon the jurisdiction in which the pertinent property is situated, create lesser interests, varying from a profit a prendre to a determinable interest in the minerals. In some jurisdictions, notably non-U.S. jurisdictions, GREKA's subsidiaries' interest is only a contractual relationship and bestows no interest in the oil or gas in place. As is customary in the oil and gas industry, a preliminary investigation of title is made at the time of acquisition of undeveloped properties. Title investigations are generally completed, however, before commencement of drilling operations or the acquisition of producing properties. GREKA believes that its methods of investigating title to, and acquisition of, its oil and gas properties are consistent with practices customary in the industry and that it has satisfactory title to the leases covering its proved reserves. Because most of GREKA's oil and gas leases require continuous production beyond the primary term, it is always possible that a cessation of producing or operating activities could result in the loss of a lease. Assignments of interest to and/or from GREKA'S subsidiaries may not be publicly recorded. From time to time, substantially all of GREKA's properties, including its stock in its subsidiaries, are hypothecated to secure GREKA's current and future indebtedness. GREKA's subsidiaries' working interest in properties may be subject to lienholders by non-payment. In the event of GREKA's non-payment or untimely payment of its obligations, GREKA expects liens to be filed against its assets and to be subject to lawsuits. Oil and gas leases in which GREKA'S subsidiaries have an interest may be deficient, require ratifications and be subject to action by GREKA subsidiaries. Average Sales Price and Production Cost The following table sets forth information concerning average per unit sales price and production cost for GREKA's oil and gas production for the periods indicated: Year Ended December 31, ------------------------ 2000 2001 2002 ------ ------ ------ Average sales price per BOE $22.14 $19.51 $21.89 Average production cost per BOE $ 5.51 $ 7.87 $ 4.90 Asphalt Refinery GREKA owns an asphalt refinery in Santa Barbara County, California through a wholly owned subsidiary. The refinery is a fully self-contained plant with steam generation, mechanical shops, control rooms, office, laboratory, emulsion plant and related facilities, and is staffed with a total of 17 operating, maintenance, laboratory and administrative personnel. Real Estate Activities GREKA'S subsidiaries from time to time purchased real estate in conjunction with their acquisition of oil and gas and refining properties in California and plan to continue this practice. At December 31, 2002, the Company owned through its subsidiaries approximately 3,300 acres in Santa Barbara County, California. GREKA has used a portion of its real estate holdings for leased agricultural purposes. GREKA plans to retain some of these real estate holdings for asset appreciation which may include developmental activities at a future date. 22 Offices GREKA leases approximately 1,000 square feet of office space at 630 Fifth Avenue, Suite 1501, New York, New York, for its executive offices through September 30, 2004. GREKA's other offices are located in Santa Maria, California; and Beijing, China. In July 2002, due to the planned divestiture of related assets, GREKA closed its Houston, Texas office. Item 3. Legal Proceedings Bank of Texas, N.A. v. Greka AM, Inc. and GREKA Energy Corporation (Case No. 02-00771, 160th Judicial District Court of Dallas County, Texas, January 2002). In March 2003, the parties entered into a Settlement Agreement and Full Release resolving all outstanding issues. The settlement agreement provided full release of the Company upon repayment of the outstanding balance, which occurred in March 2003. People of State of California, et al. v. Greka SMV, Inc. (Case No. 1114292, Superior Court of State of California, County of Santa Barbara, Santa Maria Division, December 2002). Plaintiffs brought an action against GREKA's subsidiary seeking damages of approximately $1 million for alleged statutory violations relating to a fire caused by a third party, that, ignoring GREKA's instructions, entered GREKA's operations which were being conducted in accordance with common industry practice. GREKA has submitted this matter as an insurance claim, and plans to vigorously defend all claims asserted. The litigation is in its preliminary, pre-discovery stage. Union Oil Company of California, dba Unocal v. GREKA, et al. (Case No. 1125964, Superior Court of State of California, County of Santa Barbara, Santa Maria Division, December 2002). Plaintiff brought an action against GREKA and its subsidiaries seeking damages of approximately $6.25 million for alleged breach of contract claiming that, as successor-in-interest to Saba under the terms of the contract, the Company failed to abandon a certain number of wells or provide an acceptable abandonment plan, and failed to have in place instruments securing the abandonment. GREKA plans to vigorously defend all claims asserted. The litigation is in its preliminary, pre-discovery stage. From time to time, the Company and its subsidiaries are a named party in legal proceedings arising in the ordinary course of business. While the outcome of such proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the Company's financial condition or results of operations. Item 4. Submission of Matters to a Vote of Security Holders At the Annual Meeting of Shareholders held on December 5, 2002, the following individuals were elected to the Board of Directors to serve for a 3-year term ending 2005 as Class C directors: Votes For Votes Withheld --------- -------------- Dai Vaughan 3,805,812 320,312 Kenton D. Miller 3,809,717 316,407 23 PART II Item 5. Market for Common Equity and Related Stockholder Matters Our common stock is listed for trading on the Nasdaq National Market ("NASDAQ") under the symbol "GRKA". Prior to March 25, 1999, the trading symbol was "HVNV". Except for a period from August to December of 1997, GREKA's common stock has been quoted on NASDAQ since February 19, 1993. The following table sets forth, for the periods indicated, the high and low closing bid quotations per share of GREKA common stock as reported on the Nasdaq National Market. Our common stock quotations represent inter-dealer quotations, without retail markup, markdown or commissions, and may not represent actual transactions. There can be no assurance that a public market for GREKA's common stock will be sustained in the future. Bid --- Quarter Ended Low High March 31, 2000 $8.563 $9.500 June 30, 2000 8.625 8.813 September 30, 2000 14.375 15.688 December 31, 2000 12.750 13.438 March 31, 2001 12.250 14.813 June 30, 2001 10.000 14.375 September 30, 2001 7.500 11.600 December 31, 2001 6.950 9.150 March 31, 2002 6.010 8.630 June 30, 2002 4.580 7.330 September 30, 2002 4.750 6.290 December 31, 2002 3.760 6.120 On March 17, 2003 there were approximately 888 registered holders of GREKA's common stock. Based on a broker count, GREKA believes at least an additional 3,700 persons are shareholders with street name positions. Holders of GREKA common stock are entitled to receive such dividends as may be declared by GREKA's Board of Directors. GREKA has not yet paid any cash dividends, and the Board of Directors of GREKA presently intends to pursue a policy of retaining earnings for use in GREKA's operations and to finance expansion of its business. The declaration and payment of dividends in the future, of which there can be no assurance, will be determined by our Board of Directors in light of conditions then existing, including our earnings, financial condition, capital requirements and other factors. In April 2002, the Company granted to IPH the right and option to purchase up to 400,000 shares of common stock of the Company at an exercise price of $6.00 per share for the first 200,000 shares and at an exercise price of $6.50 per share for the remaining 200,000 shares. The options were granted in consideration of IPH arranging for an irrevocable standby letter of credit having a term expiring on September 29, 2003 and in the amount of $4 million in favor of the Company's creditor that loaned $5.1 million to the Company as a bridge facility. Such options shall be exercisable during a period of five days from the date that IPH receives written notice from the Company that the letter of credit has been surrendered in connection with the loan repayment, expired, or tendered to the bank in connection with a draw thereunder. These options are exempt from registration pursuant to Section 4(2) of the Securities Act. In October 2002 and in consideration of the transfer to IPH of the $4 million balance of the $5.1 million bridge facility, we amended and restated our grant to IPH of its right and option to purchase up to 400,000 shares of common stock of the Company at an exercise price of $6.00 per share for the first 200,000 shares and $6.50 per share for the remaining 200,000 shares. Such options shall be exercisable beginning on the earlier of March 31, 2003 or changes in capitalization of the Company and ending on the later of September 30, 2003 or fifteen days after the full repayment of the loan. These options are exempt from registration pursuant to Section 4(2) of the Securities Act. 24 In June 2002 and in consideration of the $30 million of secured debt institutionally placed, the Company granted to the note holders and the collateral agent warrants to purchase up to an aggregate 150,000 shares of common stock of the Company at an exercise price of $0.01 per share and expiring in ten years. In October 2002 and in consideration of the $12.5 million of secured debt institutionally placed, which accretes up to $14.5 million until maturity, the Company granted to the collateral agent warrants to purchase up to an aggregate of 80,000 shares of common stock of the Company at an exercise price of $0.01 per share and expiring in ten years. Item 6. Selected Financial Data The following table sets forth selected consolidated financial data for the Company as of the dates and for the periods indicated. The financial data for each of the five years ended December 31, 2002, were derived from the Consolidated Financial Statements of the Company. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with the Company's financial statements included elsewhere in this report. 25

~~Proved~~Years ~~Reserves,~~Ended ~~net~~December ~~PV-10~~31, ~~Value Gross Oil Gas Property Wells (MBbls) (MMcf) MBOE Dollar Value %~~ -------- ------- -------------------------------------------- 2002 2001 2000 1999 1998 -------- -------- -------- -------- ------- (In thousands, except per share data) ~~California~~Statement of Operations: ~~Integrated~~Revenues ~~Ops~~....................................... ~~328~~$ 528,~~638~~911(1) $ 40,755 $ 49,067(2) $ 29,~~769~~138(3) 6$ 146 Production and product costs ................... $ 16,~~142~~258(1) $ 3724,~~546~~782 22$ 25,200(2) $ 17,821(3) $ 121 Sales, general and administration expenses ..... $ 9%,183 E$ 8,274 $ 7,195 $ 3,205 $ 1,542 Depletion, depreciation &P amortization ................................. ~~136~~$ 3,~~687~~245 ~~964~~$ 5,579 $ 3,~~862~~592 $ 263,~~623~~024 16$ 333 Impairment of Long-lived Assets.2%........... ~~Total~~.... ~~California~~$ 5,961 $ -- $ 1,882 $ -- $ 3,171 Gain on sale of properties $ 3,960 $ -- $ -- $ -- $ -- Interest Expense, net .......................... ~~464~~$ 9,~~325~~424 3$ 4,~~734~~157 $ 4,535 $ 1,860 $ (51) Other Income (Expenses), net ................... $ 1,151 $ (5,540)(4) $ - $ 733 $ 9 Minority Interest .............................. $ -- $ -- $ -- $ 21 $ -- (Benefit) Provision for Income taxes ........... $ (33) $ (37) $ 362 $ 46 $ -- Equity in Loss of Saba.......................... $ -- $ -- $ -- $ 569 $ 586 Cumulative effect of change in accounting principle $ -- $ -- $ 853 $ -- $ -- Net (loss) income ............................. $(10,~~004~~083) $ 64(7,~~169~~614) 39$ 4,457 $ 3,367 $(5,548) (Loss) income per common share: Basic net (loss) income per share .............. $ (2%.11) ~~Louisiana~~$ (1.67) $ 1.00 $ 0.80 $ (3.25) Diluted net (loss) income per share . . . . 28. . $ (2.11) $ (1.67) $ .99 $ .75 $ (3.25) Cash dividend per share ........................ $ -- $ -- $ -- $ -- $ -- Basic weighted average common shares outstanding ........................... 4,~~000~~768 144,~~140~~555 4,~~571~~476 $4,203 861,~~966~~703 53Diluted weighted average common shares outstanding ........................... 4,768 4,555 4,763 4,801 1%,703 ~~Other~~Balance ~~United~~Sheet ~~States~~Data (end of period): Working Capital (deficit).......... ~~212~~............ ~~687~~$(14,929) $(50,355)(5) $ (2,~~201~~664) $(14,176) $(1,~~087~~828) Net property and equipment ..................... $ 1278,~~742~~869 ~~7.8%~~$ ~~Total~~89,465 ~~United~~$ ~~States~~77,182 $ 70,287 $ 4,426 Total assets ................................... ~~704~~$ 1297,~~012~~589 $100,049 $ 98,813 $ 84,214 $20,~~075~~807 15Long-term obligations .......................... $ 47,~~662~~665 $~~163~~ 9,~~877~~139 ~~100~~$ 28,207 $ 15,696 $ 53 Total stockholders' equity .0%.................... $ 26,051 $ 33,166 $ 40,211 $ 33,378 $18,505

(1) Revenues and production and products costs are affected by the sale of certain exploration and production assets in 2002. (2) Revenues and production and products costs are affected by the full consolidation of the subsidiary engaged in the refinery operations effective May 1999. (3) Revenues and production and products costs are affected by the acquisition of SABA in early 1999. (4) Other expense reflects costs incurred in connection with settlement of litigation. (5) Includes reclassification of long-term debt to current due to a technical default. 26 Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations Overview GREKA is an independent integrated energy company. Our oil and gas production, exploration and development activities are concentrated in our properties in California where we also own and operate an asphalt refinery. We supply our asphalt refinery with equity oil, which is the crude oil we produce from our surrounding heavy crude oil reserves, and we also utilize crude oil purchased from third party producers. We believe that our vertically integrated operations reduce our exposure to material volatile swings in crude oil prices. Historically we have also engaged in oil and gas exploration, development and production from our properties in Louisiana, Texas and New Mexico which operation has substantially been sold as part of our strategic, internal reorganization. In addition, we have interests in coalbed methane properties and production sharing contracts in China. Results of Operations Comparison of Years Ended December 31, 2002 and 2001 Revenue decreased from $40,755,282 for 2001 to $28,910,845 for 2002. This 29% decrease is the net effect of a decrease in revenue from our upstream activities by 59% from $14,151,828 in 2001 to $5,846,409 in 2002 resulting from the effects of the Company's restructuring plan and sale of its interests in the Potash Field, Manila Village and other oil and gas properties, in addition to a decrease of 10% in revenue from our downstream activities (asphalt sales) from $25,255,580 in 2001 to $22,751,809 in 2002. The decrease is the total effect of a 6% volume decrease from 998,640 Bbls in 2001 to 939,301 Bbls in 2002 or $1,500,683. Coupled with a 4% price decrease in the weighted average selling price per barrel of asphalt products from $25.29 in 2001 to $24.22 in 2002 or $1,003,088, this was also compounded by a decrease in other income from the farm operation and other sources by $1,035,248, from $1,347,874 in 2001 to $312,626 in 2002. Production and product costs decreased from $24,781,938 for 2001 to $16,258,337 for 2002. This 34% decrease consists of a 57% decrease in production costs from upstream activities from $5,219,044 in 2001 to $2,254,536 in 2002 due to the effect of the Company's restructuring plan, coupled with a 28% decrease in production costs from downstream activities from $19,562,894 in 2001 to $14,003,800 in 2002. The decrease of $5,559,094 is the aggregate effect of 6% decrease in volume or a reduction of production costs of $1,162,421 coupled with a 24% decrease in cost per barrel from $19.59 to $14.91, or a further reduction of $4,396,673. The decrease in the cost per barrel is due to a 24% increase of the average daily throughput from 2,369 Bbls in 2001 to 2,944 Bbls in 2002 coupled with a material decrease in the percentage of daily average throughput from third party crude (feedstock) from 47% or 1,277 Bbls in 2001 to 8% or 250 Bbls in 2002. The decrease in purchases of third party crude is due to the acquisition of properties, which increased contribution to feedstock from equity crude by approximately 1,500 Bbls per day from approximately 1,000 to 2,500 Bbls per day. Sales, general and administration expenses increased by 11% from $8,274,183 for 2001 to $9,182,828 for 2002. The increase is primarily due to incremental freight cost associated with shipment of distillates to customers, audit fees and acquisition-related expenses. Depreciation, depletion and amortization decreased significantly from $5,578,899 for 2001 to $3,244,847 for 2002. This decrease of 42% is the result of lower depletion rate for 2002 of $3.12 per barrel compared to $4.48 per barrel for 2001 coupled with a 23% decrease in volume of production from a weighted daily average of 3,179 BOE in 2001 to 2,441 BOE for 2002. The lower depletion rate resulted from 110% increase in the reserves from 13,576 MBOE for 2001 to 28,542 MBOE for 2002. This, however, was mitigated by a 52% increase in the related total oil and gas properties asset base from $60.7 million for 2001 to $91.8 million for 2002. 27 The Company reported an operating loss of $1,776,608 for 2002 compared to an operating income of $ 2,120,262 for 2001. This 184% decrease is due to: i) impairment of long-lived assets covering Indonesia and the limestone properties for an amount of $5,961,187, which was partly offset by a gain on the sale of real estates in California in the amount of $3,959,746 and, ii) a decrease in operating income of $1,895,429 primarily deriving from a decrease in oil and gas revenues due the sale of certain oil and gas properties in 2002. Interest expense increased from $4,157,110 for 2001 to $9,423,521 for 2002 as a result of an increase in the interest bearing loans outstanding from a weighted average of approximately $40 million in 2001 to $51 million in 2002 coupled with an increase in the weighted average interest rate from 10% to 18%. Other income and expenses for 2002 of $1,150,729 is primarily the net write off of capitalized financing costs of approximately $1.4 million relating to the payoff of the GMAC and bridge loans offset by write off of stale liabilities and non-recurring charges of approximately $1 million in addition to non-operating income realized from the sale of emission credits of $0.6 million. Net loss increased from $7,613,544 for 2001 to $10,082,509 for 2002 due to impairments of long-lived assets coupled with an increase in the cost of capital in addition to charges relating to issued warrants and options associated with financing activities in 2002 (see Item 5 - "Market for Common Equity and Related Stockholder Matters"). This, however, was somewhat mitigated by gains realized from sale of various real estate, discussed above. Capital expenditures increased 18% or $3,126,698 from $17,170,957 for 2001 to $20,297,655 for 2002. Capital expenditures were utilized primarily for the acquisition of oil and gas properties, as well as for drilling activities in oil and gas producing properties in California. Comparison of Years Ended December 31, 2001 and 2000 Revenue decreased by 17% or $8,311,858 from $49,067,140 for 2000 to $40,755,282 for 2001. The decrease was mostly due to both lower volume sales of 8% from 1,080,604 barrels in 2000 to 998,640 barrels in 2001, and 15% lower average sales prices of refined products from $29.26 in 2000 to $24.87 in 2001 at our integrated operations. Production and product costs decreased by 2% or $417,682 from $25,199,620 in 2000 to $24,781,938 in 2001. The overall decrease was net of an increase of 9% in the average per barrel cost from $11.20 in 2000 to $12.22 in 2001, or a total of $2,068,498 offset by a decrease of 10% in volume from 2,249,495 barrels in 2000 to 2,027,945 barrels in 2001 or a total decrease of $2,486,179. The decrease in volume of barrels of throughput at the integrated operations contributed to the overall increase in the average per barrel cost for the year. Sales, general and administration expenses increased by 15% or $1,079,662 from $7,194,521 for 2000 to $8,274,183 in 2001 due to increase in audit, legal, consulting and insurance costs coupled with costs associated with increase of personnel and related fringe benefits. Operating income decreased 81% or $9,078,639 from $11,198,901 in 2000 to $2,120,262 as a direct result of a decrease in revenues of $8,311,858 or 92% (explained above) coupled with increase in general and administration expenses and depreciation, depletion and amortization expenses. Depreciation, depletion and amortization increased 55% or $1,986,657 primarily as a result of an increase in the per barrel rate of depletion from $3.43 in 2000 to $4.80 in 2001. The increase in the depletion rate was a result of an increase of 40% in the asset base relating to oil and gas properties coupled with a decrease of 13% in the overall reserves from 15,662 MBOE in 2000 to 13,576 MBOE in 2001. 28 Interest expense decreased 8% from $4,535,174 in 2000 to $4,157,110 for 2001 mostly due to a decrease in the interest rates applied to average outstanding loan balances. Other expense, net, increased by 75%, or $4,170,693, from $5,526,613 in 2000 to $9,697,306 in 2001, mostly due to expenses and non-recurring charges associated with settlement of litigation post acquisition adjustments. Net income decreased by 271%, or $12,070,758, from a net income of $4,457,214 for 2000 to a net loss of $7,613,544 for 2001. The variance is mostly due to a 69% decrease in revenue of $8,311,858 and a 31% net increase in expenses, or $3,758,900 consisting mainly of non-recurring charges resulting from settlement of material litigation and post-acquisition adjustments. Capital expenditures increased 26% or $3,569,438 from $13,601,519 in 2000 to $17,170,957 in 2001. Capital expenditures were utilized primarily for drilling activities in E&P Americas. Cash Flows Cash provided by or used in operations decreased from an inflow of $5,317,847 for 2001 to an outflow of $14,582,896 for 2002. Net loss for the period ended December 31, 2002 contributed to $10,082,509 of cash outflow. The Company's net cash flows provided from investing activities increased from net outflows of $16,030,140 for 2001 to a net inflow of $4,294,959 for 2002. The change is the net of cash inflows from the sale of our interests in the Potash Field, Yorba Linda and other real estate properties offset by the acquisition cost of the Vintage properties and current year capital expenditures. The Company's net cash provided by financing activities increased by 79% or $4,940,517 from $6,296,697 for 2001 compared to net cash provided by financing activities of $11,227,214 for 2002. The increase of $4,940,517 is primarily a result of the Company's net proceeds from notes payable issued. Liquidity and Capital Resources The working capital deficit at December 31, 2002 of $14,928,691 decreased by $35,426,625 from a working capital deficit of $50,355,316 at December 31, 2001. Current assets increased by $453,039 from $7,389,081 at December 31, 2001 to $7,842,120 at December 31, 2002 which includes an increase of $939,277 in cash and cash equivalents from $422,103 at December 31, 2001 to $1,361,380 at December 31, 2002. The increase in the cash balance, as well as current assets is due primarily to the effect of the sale of non-core assets that had been earmarked for divestiture in accordance with the Company's restructuring plan announced in March 2002, Other changes include an increase in receivables and a decrease in inventories from $3,618,368 and $1,796,520 respectively at December 31, 2001 to $3,760,613 and $1,363,506, respectively, at December 31, 2002. Other changes included a decrease in other current assets of $655,469 from $1,552,090 at December 31, 2001 to $896,621 at December 31, 2002 mostly as a result of payment of notes receivables from both a third party and a related party. Current liabilities decreased $34,973,586 from $57,744,397 at December 31, 2001 to $22,770,811 at December 31, 2002 as a result of payment of loans to the Bank of Texas ($12,400,000) and to GMAC ($5,000,000 current portion) in addition to a decrease in accounts payable and accrued expenses of $10,653,457 from $23,751,354 at December 31 2001 to $13,097,897 at December 31, 2002 as a result of management's concerted effort to reduce aged outstanding liabilities. Although the Company decreased its working capital deficit by $35,426,625 from December 2001, the Company did continue to experience certain liquidity issues. However, as discussed in Item 1 - "Financing & Debt Restructuring Activities", the Company placed $20 million with an institutional investor through a 2-year secured credit facility. 29 In March 2003, the Company amended, with certain retrospective effects, the terms of its loan agreement, and it borrowed additional $20 million through its collateral agent by issuing 2-years promissory notes. From these proceeds, the Company paid $4.7 million to Bank of Texas and $4.1 million to IPH to retire their respective loans, and the balance, in addition to closing costs and working capital, will fund a portion of the Company's $15 million capital expenditure program for 2003. Of the $20 million, $13.5 million bears interest at a variable rate of Libor + 6.25% or 8.25%, whichever is greater, while the balance $6.5 million bears interest at a fixed rate of 9.25%. The Company paid a 4.25% closing fee, and the placement resulted in increase by approximately $10 million to the Company's total debt. See Note 9,(d)to the consolidated financial statements. The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions of our consolidated entity. The Company's growth is focused on organic production increases that are strategic and in accordance with our business plan. Historically, GREKA has relied on cash flow from operations to finance operational capitalized expenditures. In 2002, GREKA had expended $20,297,655 for its capitalized expenditures. For 2003, GREKA has budgeted $15 million for its discretionary capitalized expenditures. Factors affecting actual expenditures and investments include availability of capital and suitable investment opportunities, market volatility and economic trends. The anticipated sources of funds for such growth opportunity are cash flow from operations and external financings. Further, GREKA intends to achieve the following: . We have embarked on a complete restructuring of all our long-term and maturing debt. The debt restructuring scheduled during the second quarter is intended to payoff all remaining aged trade debt, provide availability for continued development within the Integrated Operations' business plan, continued development of our interests in China, and working capital. . Utilize cash on hand to implement an aggressive drilling program in the second and third quarters of 2003. . Continue to execute an aggressive rework program to return to production existing wells on all properties that have shut-in wells. . Utilize the in-house proprietary and cost effective horizontal drilling technology to enhance production in the Santa Maria Valley area, increasing the equity oil and gas production as well as new gas treatment facilities. . Continue to acquire assets to enhance the benefit of integrated operations that collectively provide for low cost operating expenses and high cash flow. For an analysis of certain contractual and commercial obligations in 2002 and thereafter, see "Disclosures about Contractual Obligations and Commercial Obligations and Certain Investments", shown below. The following table reflects the contractual cash obligations and other commercial commitments in the respective periods in which they are due. 30

~~Estimated~~Total ~~Proved~~Amounts ~~Oil~~Less ~~and~~than ~~Gas~~Contractual ~~Reserves~~Obligations AtCommitted ~~December~~1 ~~31,~~Year 1-2 Years 3-4 Years Thereafter ----------------------- --------- ------ ~~1998(1) 1999(1) 2000(1)~~ --------- --------- ---------- ~~Net~~(Thousands ~~oil~~of ~~reserves (MBbl~~Dollars) ~~Proved~~Debt ~~developed~~$ ~~producing~~57,930 ~~............~~$ ~~921 6~~9,~~469~~673 7$ 48,~~060~~257 ~~Proved~~-- ~~developed~~$ ~~non~~-~~producing~~- ~~........~~Operating ~~449~~Leases ~~825~~355 ~~1,309~~216 ~~Proved~~137 ~~undeveloped~~2 ~~....................~~-- ~~703 3,237 3,644~~ -------- -------- -------- ~~Total proved oil reserves (MBbl) ..... 2,072 10,532 12,012 ======== ======== ======== Net natural gas reserves (MMcf) Proved developed producing ............ 955 3,364 5,184 Proved developed non~~-~~producing ........ 1,760 5,398 4,758 Proved undeveloped .................... 2,417 8,836 10,133~~ -------- -------- -------------------- Total ~~proved~~Contractual ~~natural~~Cash ~~gas~~Obligations ~~reserves~~$ ~~(MMcf)~~58,285 ~~....................~~$ 59,~~132~~889 ~~17,598~~$ 2048,~~075~~394 $ 2 $ -- ======== ======== ======== ~~Total proved reserves (MBOE) ............. 3,006 13,732 15,662~~=====================================

In March 2003, the Company borrowed an additional $20 million, by issuing 2-year promissory notes. Out of the total proceeds of $ 20 million, $8.8 million was used to repay the current portion of long-term debt (Bank of Texas and IPH), with the remaining balance to be used to fund a portion of the Company's 2003 capital expenditures and for working capital requirements. The Company's continuation as a going concern is dependent upon its ability to successfully establish the necessary financing arrangements and implement our strategies consistent with its restructuring plans and successful 2003 capital expenditure program. Item 7A. Quantitative and Qualitative Disclosures About Market Risk To some extent, at December 31, 2002, the Company's operations were exposed to market risks primarily as a result of changes in commodity prices and interest rates. The Company does not use derivative financial instruments for speculative or trading purposes. Interest Rate Risk - The Company is exposed to the impact of interest rate changes. The Company has approximately $3.3 million outstanding under its Revolving credit agreement. Changes in the interest rate on such debt are deemed not be material to the financial position of the Company. In addition, the Company issued $25 million in senior notes and $5 million in senior subordinated notes with an initial interest of 15% and 21% per year, respectively. The interest rates payable are adjusted downward based on the Company achieving certain financial targets and could result in a minimum interest of 11% and 17% for the senior and subordinated notes, respectively. The Company did not achieve these targets as of December 31, 2002. Commodity price risk - The Company is subject to the market risk associated with changes in commodity prices of the underlying crude oil and refined products. Credit Risk - Financial instruments which potentially subject the Company to credit risk consist principally of trade receivables. Concentration of credit risk with respect to trade receivables is mitigated by the stability, longevity and financial soundness of the Company's customers. Although four customers accounted for more than 10% each of the Company's sales, these customers are not currently considered a credit risk since most of their sales are to funded city, state or federal government projects. Inflation GREKA does not believe that inflation will have a material impact on GREKA's future operations. 31 Critical Accounting Policies and Use of Estimates Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant estimates involves the assessment of the amount of proved natural gas and oil reserves and the estimate of future development and plug and abandonment costs. Actual results could differ from those estimates. Full Cost Accounting - The Company uses the full cost method to account for our natural gas and oil properties. Under full cost accounting, all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are capitalized into a "full cost pool". Capitalized costs include costs of all unproved properties, internal costs directly related to our natural gas and oil activities. The Company amortizes these costs using a unit-of-production method. Greka computes the provision for depreciation, depletion and amortization quarterly by multiplying production for the quarter by a depletion rate. The depletion rate is determined by dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the quarter. Unevaluated properties and related costs are excluded from our amortization base until a determination is made as to the existence of proved reserves. The amortization base includes estimates for future development costs, as well as future abandonment and dismantlement costs. Estimates of proved reserves are key components of our depletion rate for natural gas and oil properties and our full cost ceiling test limitation. See Note 13 to the consolidated financial statements, "Supplemental Oil and Gas Information". Because there are numerous uncertainties inherent in the estimation process, actual results could differ from the estimates. Inventories - The Company values its inventory on the weighted average cost method. The weighted average cost method is considered the preferable method because the primary inventorable cost at the refinery is crude oil for which the price can fluctuate significantly. The weighted average method balances the impact of short term fluctuations in crude oil pricing on the Company's refinery inventory levels. Recent Accounting Pronouncements A summary of the recent accounting pronouncements, issued by the Financial Accounting Standards Board ("FASB"),that may affect the Company are presented below. The Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations," requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. SFAS No. 142, "Goodwill and Other Intangible Assets", addresses accounting for the acquisition of intangible assets and accounting for goodwill and other intangible assets after they have been initially recognized in the financial statements. We do not currently have goodwill or other similar intangible assets' therefore, the adoption of the new standard on January 1, 2002, has not had a material effect on our consolidated financial statements. SFAS No. 143, "Accounting for Asset Retirement Obligations," addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 became effective on January 1, 2003 and early adoption is encouraged. SFAS No. 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded 32 amount, a gain or loss is recognized. Currently, the Company includes estimated future costs of abandonment and dismantlement in its full cost amortization base and amortizes these costs as a component of its depletion expense. The Company is continuing to revise its calculation of the impact the new standard will have on the consolidated financial statements and the Company does not believe there will be a material impact to the consolidated financial statements. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became effective on January 1, 2002, and addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for the Long-Lived Assets to Be Disposed Of" and Accounting Principles Board ("ABP") Opinion No. 30, "Reporting the Results of Operations-Reporting the Effects of Disposal of Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 retains the fundamental provisions of SFAS NO. 121 and expands the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The standard had no impact on the consolidated financial statements for the year ended December 31, 2002. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds the provisions of SFAS No. 4 that require companies to classify certain gains and losses from debt extinguishments as extraordinary items, eliminates the provisions of SFAS No. 44 regarding transition to the Motor Carrier Act of 1980 and amends the provisions of SFAS No. 13 to require that certain lease modifications be treated as sale leaseback transactions. The provisions of SFAS No. 145 related to classification of debt extinguishment are effective for fiscal years beginning after May 15, 2002. The provisions of SFAS No. 145 related to lease modifications are effective for transactions occurring after May 15, 2002. The Company early adopted the provision of SFAS No. 145, as permitted, with respect to the classification of gains or losses from debt extinguishment. In 2002 the Company recorded approximately $265,000 of gain on extinguishment of debt as "other income". In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"). SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for costs associated with the exit or disposal of an activity be recognized when the liability is incurred. This statement also established that fair value is the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. The FASB has issued SFAS No. 148 "Accounting for Stock-Based Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. As of December 31, 2002, the Company accounts for stock-based employee compensation in accordance with APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. 33 In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees", which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of the Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. Under this Interpretation, at the inception of guarantees issued or modified after December 31, 2002, we will record the fair value of the guarantee as a liability, with the offsetting entry being recorded based on the circumstances in which the guarantee was issued. The Company does not have any third party guarantees outstanding other than certain guarantees issued in connection with the Company's debt. Such debt is recorded on the Consolidated Balance Sheet at December 31, 2002. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB 51". This Interpretation requires that the primary beneficiary in a variable interest entity consolidate the entity even if the primary beneficiary does not have a majority voting interest. The consolidation requirements of this Interpretation are required to be implemented for any variable interest entity created on or after January 31, 2003. In addition, the Interpretation requires disclosure of information regarding guarantees or exposures to loss relating to any variable interest entity existing prior to January 31, 2003 in financial statements issued after January 31, 2003. We do not believe that this Interpretation will have a material effect on our financial condition or results of operations. Item 8. Financial Statements Please see accompanying Index to Financial Statements and Schedule commencing on page F-1. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures In May 2001, the Company engaged Hein + Associates LLP to replace Arthur Andersen LLP as its independent public accountants to audit its consolidated financial statements for the year ending December 31, 2001. Refer to the Company's Form 8-K filed on May 21, 2001. In December 2001, the Company appointed Deloitte & Touche LLP to replace Hein + Associates LLP as its independent public accountants to audit its consolidated financial statements for the year ending December 31, 2001. Refer to the Company's Form 8-K filed on January 3, 2002. 34 PART III Item 10. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of the Exchange Act The directors and executive officers of GREKA at December 31, 2002 are as follows: Name Since Age Positions ----- --- --------- Randeep S. Grewal 38 Chairman of the Board, Chief Executive September 1997(1) Officer and President, Class A Director Dr. Jan F. Holtrop 67 Class B Director September 1997(2) George G. Andrews 77 Class B Director July 1998(3) Dai Vaughan 63 Class C Director March 1999(4) Kenton D. Miller 50 Class C Director October 2000(4) Brent E. Stromberg 58 Vice President-Operations December 2001 Susan M. Whalen 41 Vice President-Asset Management, Secretary August 2001 Richard "Sam" R. Lembcke 66 Vice President-Development December 2001 Max A. Elghandour 52 Chief Financial Officer August 2001 (1) term as Director expires 2004 (2) term as Director expires 2003 (3) deceased March 2003 (4) term as Director expires 2005 Randeep S. Grewal. Since September 1997, Mr. Grewal has served as our Chairman of the Board, Chief Executive Officer and President. From April 1997 to September 1997, Mr. Grewal served as Chairman and Chief Executive Officer for Horizontal Ventures, Inc., an oil and gas horizontal drilling technology company that became a subsidiary of our predecessor in September 1997. From 1993 to 1996, Mr. Grewal was the Corporate Vice President for the Rada Group with principal responsibilities for its global expansion and related operations. He has also been involved in various joint ventures, acquisitions, mergers and reorganizations since 1986 in the United States, Europe and the Far East within diversified businesses. Mr. Grewal has a Bachelor of Science degree in Mechanical Engineering from Northrop University. Dr. Jan Fokke Holtrop. Dr. Holtrop has been a Class B Director of GREKA since September 1997. Since 1989 he has been a senior Production Technology professor at Delft University of Technology within the Faculty of Petroleum Engineering and Mining in The Netherlands. Prior to Delft University, he served in various positions within the Shell Oil Company where he started his career in 1962. This includes mining engineering, reservoir engineering and petroleum engineering field work in at least 14 different countries, as well as deep sea 35 drilling, coal production and coal exploration operations, well technology research, and well design, drilling and production operations. Dr. Holtrop has more than 40 years of experience within the oil and gas exploration, drilling and production industry with a global hands-on background. Dr. Holtrop has a Ph.D. and a MSC in Mining Engineering from Delft University of Technology. George G. Andrews. Mr. Andrews became a Class B Director of GREKA in July 1998 and served on GREKA's Board until he passed away in March 2003. He had been a consultant and private investor since his retirement from the oil and gas industry in 1987. From 1982 until 1987 he was employed as Corporate Vice President of Intercontinental Energy Corporation of Englewood, Colorado and directed the company's land acquisition, lease and management operations. Between June 1981 and November 1982, Mr. Andrews was Vice President of Shelter Hydrocarbons, Inc. of Denver, Colorado where he directed all land management and operation procedures. From 1979 to June of 1981, Mr. Andrews was Senior Landman for the National Cooperative Refinery Association in Denver, Colorado. Mr. Andrews obtained his B.S. degree in 1947 from the University of Tulsa. Kenton D. Miller. In October 2000, Mr. Miller became a Class C Director of GREKA. Since 1991, Mr. Miller has maintained a private consulting practice specializing in management advisory services for a diverse group of petroleum related companies. His consulting services are oriented to improving financial performance for clients utilizing the combination of financial accounting with operations principles and providing assistance with strategic acquisitions or divestitures. Mr. Miller has 30 years of oil and gas experience in reservoir engineering, field operations and management, primarily with Ladd Petroleum Company, BP Amoco and Cities Service Oil Company. His management experience includes the successful drilling of the first commercial horizontal well in Oklahoma and the lead engineering of the early Beaufort Sea exploratory wells drilled. Mr. Miller has been a Registered Professional Petroleum Engineer since 1984 and a Certified Public Accountant since 1994. He has a Bachelor of Science in Petroleum Engineering from the University of Tulsa. Dai Vaughan. Mr. Vaughan has been a Class C Director of GREKA since March 1999. He has been an independent management consultant since 1994 with concentrated experience in business plan development, implementation, and business turn-arounds. From 1985 until 1994, he was with Continental Airlines, most recently as Manager of Aircraft Acquisition. Mr. Vaughan has served in numerous positions in his 44 year career in the airline industry with Pan American Airlines, Eastern Airlines and finally Continental Airlines, including Systems Engineering, Aircraft Maintenance and Aircraft Acquisition. Mr. Vaughan received a HNC degree (B.S. equivalent) in Electrical Engineering. Brent E. Stromberg. Mr. Stromberg joined us in May 1999 as General Manager - Refinery Operations and in March 2000 was appointed Vice President -- Integrated Operations in Santa Maria, California. He was appointed Vice President-Downstream Operations in December 2001 and Vice President-Operations in July 2002. Mr. Stromberg's experience of 19 years in the management of crude oil operations includes 18 years with Petro Source Corporation/Crown Asphalt in Salt Lake City. From 1981 to 1999, he served in several management positions, including Santa Maria Project Manager, Transportation Manager, and Motor Gasoline Blending and Marketing Manager. Mr. Stromberg received a Bachelor of Arts in Business Management and a Masters in Business Administration Degree from the University of Utah. Susan M Whalen. Ms. Whalen served as General Counsel for Saba Petroleum Company from 1997 until 1999, when Saba was acquired by GREKA. Following the acquisition she served as our Vice President of Legal & Corporate Affairs and as Corporate Secretary. In October 2000 she was appointed Corporate Liaison to our Integrated Operations division and in August 2001 she was appointed our Vice President of Corporate Affairs. In July 2002, Ms. Whalen was appointed Vice President-Asset Management. Prior to joining Saba in 1997, Ms. Whalen was involved in various niche-market product developments within the retail industry for 10 years. Ms. Whalen received her J.D. degree from Western State University - College of Law. 36 Richard "Sam" R. Lembcke. Mr. Lembcke joined us in February 2000 as Vice President of the E&P Americas division and, after his appointment in December 2001 as Vice President-Upstream Operations, he was appointed as Vice President-Business Development in July 2002. Mr. Lembcke possesses vast experience in the oil and gas industry that spans over 40 years. Throughout his tenure in the industry, he has held a series of positions with increasing responsibility, including President from 1996 to 2000 of Gulf Tech, a Louisiana focused oil and gas company, President and General Manager of Ultramar Oil & Gas Limited in Houston, Texas from 1989 to 1992, and as Vice President - Manager of Operations from 1983 to 1989. From 1978 to 1983, Mr. Lembcke served as Executive Vice President and Director for Marion Drilling Services Company. From 1960 to 1978, he served in several positions for Union Oil Company of California. Further, he has served as past President of the American Petroleum Institute and Society of Petroleum Engineers. Mr. Lembcke received a Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma. Max A. Elghandour. Mr. Elghandour joined us in May 2001 as Chief Financial Officer. He has over 20 years of financial and operational experience in the oil, gas, and chemical industries. Prior to joining us, Mr. Elghandour spent 16 years as a member of the senior financial team at Elf Aquitaine, now Totalfinaelf, in progressive functional and engaging capacities in the United States, France and the Middle East. He has a Bachelor of Science in Accounting from Saint Francis College and is a Certified Public Accountant. He is a member of the American Institute of Certified Public Accountants and the New York State Society of Certified Public Accountants. During 2002, the Board of Directors met twelve times. No director attended less than 75% of the meetings. There are no family relationships among the directors. There are no arrangements or understandings between any director and any other person pursuant to which that director was elected. During the past five years, there have been no petitions under the Bankruptcy Act or any state insolvency law filed by or against, nor have there been any receivers, fiscal agents, or similar officers appointed by any court for the business or property of any of GREKA's directors or executive officers, or any partnership in which any such person was a general partner within two years before the time of such filing, or any corporation or business association of which any such director or executive officer was an executive officer within two years before the time of such filing. During the past five years, no incumbent director or executive officer of GREKA has been convicted of any criminal proceeding (excluding traffic violations and other minor offenses) and no such person is the subject of a criminal prosecution which is presently pending. Committees At December 31, 2002, GREKA's Audit Committee, whose charter was adopted in June 2000 and amended in October of 2002, consists of Messrs. Miller, Andrews and Vaughan, and its Compensation Committee consists of Messrs. Grewal, Vaughan and Andrews. The Board of Directors selects director nominees and will consider suggestions by shareholders for names of possible future nominees delivered in writing to the Secretary of GREKA on or before November 30th in any year. The Audit Committee met three times during 2002, and the Compensation Committee met twice during 2002. Section 16(a) Beneficial Ownership Reporting Compliance Based solely on a review of reports filed with GREKA, all directors, executive officers and beneficial owners of more than five percent of GREKA common stock timely filed all reports regarding transactions in GREKA's securities required to be filed during the last fiscal year by Section 16(a) of the Securities Exchange Act of 1934, except one Form 4 for Mr. Stromberg. 37 Item 11. Executive Compensation The following summary compensation table sets forth in summary form the compensation received during each of GREKA's last three completed fiscal years by the executive officers of GREKA, except no disclosure is required for those earning gross compensation less than $100,000. Executive Compensation

~~Estimated~~Summary ~~Present~~Compensation ~~Value~~Table ofAnnual ~~Future~~Compensation ~~Net~~Long ~~Revenue~~Term ~~(In~~Compensation ~~thousands) At December 31,~~ ----------------------- --------------------------- ~~1998~~Restricted Securities Name and principal stock awards underlying All other position Year Salary(1$) ~~1999~~Bonus($)(1) ~~2000~~(1$) options/SARS compensation ------------------ ---- --------- ----------- PV-10----------- ~~Value~~------------ ~~Proved~~------------ ~~developed~~Randeep ~~producing~~ S.~~.......~~ $Grewal, 22002 $402,~~301~~101 $6,522 39-- -- $284,~~689~~144(2) Chairman and Chief 2001 $353,777 67$8,~~080~~844 ~~Proved~~-- ~~developed non~~-~~producing~~- ~~....~~$ 112,~~629~~000(3) 8Executive Officer 2000 $290,~~977~~269 37-- -- 410,~~160~~000 ~~Proved~~$ ~~undeveloped~~12,000(3) Brent E.~~...............~~ 1Stromberg,~~169~~ 182002 $104,~~487~~056 59$6,~~637~~522 -- -- -- VP-Operations 2001 $ 97,386 $8,844 -- -- -- Susan M. Whalen, 2002 $109,144 $6,522 -- -- -- VP-Asset Management 2001 $ 93,445 $8,844 -- -- -- Richard R. Lembcke, 2002 $118,687 $6,522 -- -- -- ~~Total~~VP-Development ~~..........................~~2001 $ 5114,~~100~~471 $8,844 67-- -- -- Max A. Elghandour,~~153~~ 2002 $160,000 ~~163~~-- -- -- -- Chief Financial Officer 2001 $103,~~877~~385 ~~==========~~-- ~~==========~~-- ~~==========~~45,000 --

(1) The bonus paid to the executive officers of GREKA in 2001 and 2002 was their participation in the Company's NPSP. The executive officers of GREKA were not paid any bonuses during 2000. (2) Auto expense allowance and life-long valuation of 2% overriding royalty from acquired properties. (3) Auto expense allowance. No other form of compensation was paid during 2000, 2001 or 2002. No other executive officer or director of GREKA received total compensation in excess of $100,000 during the last three fiscal years. At December 31, 2002, GREKA had authorized 1.4 million options to acquire shares of common stock of GREKA, of which none were granted in 2002, to employees, directors and consultants of the Company. During 2002, a total of 2,000 options terminated through attrition and no options had been exercised, leaving the total option grants outstanding as of December 31, 2002 at 1,106,000 options. 38 Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values Value of Number of unexercised Shares unexercised in-the-money acquired options/SARS options/SARS on Value at FY-end(#) at FY-end($) exercise realized exercisable/ exercisable/ Name (#) ($) unexercisable unexercisable ---- -------- -------- -------------- ------------- Randeep S. Grewal 0 - 520,000/ 0 $0/$0 Brent E. Stromberg 0 - 50,000/ 25,000 $0/$0 Susan M. Whalen 0 - 35,000/ 10,000 $0/$0 Richard R. Lembcke 0 - 50,000/ 25,000 $0/$0 Max A. Elghandour 0 - 15,000/ 30,000 $0/$0 Employment Contracts and Termination Agreements On September 9, 1997, GREKA entered into a five-year employment agreement with Randeep S. Grewal. This agreement was amended on October 14, 1998, and on November 3, 1999 the Board of Directors adopted an amended and restated employment agreement for Mr. Grewal (the "Restated Agreement"). Under the terms of the Restated Agreement, Mr. Grewal's annual salary is $287,500 subject to an annual increase effective on the anniversary date. Mr. Grewal participates in GREKA's benefit plans and is entitled to bonuses and incentive compensation as determined by the board of directors of GREKA. The Restated Agreement also allows Mr. Grewal to receive an assignment of a 2% overriding royalty of all oil and gas properties of GREKA and to receive fringe benefits which include an automobile allowance of $1,000 per month. Under the original agreement, 31,500 shares of GREKA common stock were issued to Mr. Grewal. The term of the Restated Agreement is through the fifth anniversary of December 31, 1999; however, it automatically rolls over so that it is a minimum of three years unless sixty days prior to any anniversary date the Company notifies Mr. Grewal that the change of control period shall not be extended. A change of control termination clause was added which is intended to deter hostile changes of control by providing a substantial termination payment should Mr. Grewal terminate his employment or be terminated as a result of a change of control. The Restated Agreement is terminable for cause or by the death or disability of Mr. Grewal. In addition, the Restated Agreement may be terminated by Mr. Grewal in the event of any diminution by GREKA in Mr. Grewal's position, authority, duties or responsibilities. Upon termination of the Restated Agreement by GREKA for any reason other than for cause, death or disability, or upon termination of the Restated Agreement by Mr. Grewal in the event of any diminution by GREKA in Mr. Grewal's position, authority, duties or responsibilities, GREKA is obligated to pay within 30 days after the date of termination: (a) Mr. Grewal's base salary through the date of the severance period, (b) Mr. Grewal's base salary for the balance of the term of the agreement if the date of termination is within the first five years of the employment agreement (base salary is the salary rate in effect at the date of termination), (c) the annual bonus paid to Mr. Grewal for the last full fiscal year during the employment period, and (d) all amounts of deferred compensation, if any. Director Compensation Each director, who is not an employee of GREKA, is reimbursed for expenses incurred in attending meetings of the board of directors and related committees. At December 31, 2002, GREKA had four outside directors. No compensation was paid to any outside director during fiscal 2002 and none is planned for the immediate future. 39 GREKA has no knowledge of any arrangement or understanding in existence between any executive officer named above and any other person pursuant to which any such executive officer was or is to be elected to such office or offices. All officers of GREKA serve at the pleasure of the board of directors. No family relationship exists among the directors or executive officers of GREKA. There is no person who is not a designated officer who is expected to make any significant contribution to the business of GREKA. Any officer or agent elected or appointed by the board of directors may be removed by the board whenever in its judgment the best interests of GREKA will be served thereby without prejudice, however, to any contractual rights of the person so removed. Future Transactions All transactions between GREKA and an officer, director, principal stockholder or affiliate of GREKA will be approved by a majority of the uninterested directors, only if they have determined that the transaction is fair to GREKA and its shareholders and that the terms of such transaction are no less favorable to GREKA than could be obtained from unaffiliated parties. Item 12. Security Ownership of Certain Beneficial Owners and Management The following table presents, as of March 17, 2003 the common stock ownership of each person known by GREKA to be the beneficial owner of five percent or more of GREKA's common stock, all directors and officers individually, and all directors and officers of GREKA as a group. Except as noted, each person has sole voting and investment power with respect to the shares shown. GREKA is not aware of any contractual arrangements or pledges of GREKA's securities which may at a subsequent date result in a change of control of GREKA. As of March 17, 2003, there were 4,951,451 shares of GREKA common stock issued and outstanding. Amount of Beneficial Ownership Name and Address of Beneficial Owner Common Stock(1) Percent of Class ------------------- --------------- ---------------- Strong Capital Management, Inc. 511,388 10.33% Richard S. Strong 100 Heritage Reserve Menomonee Falls, WI 53051 Wynnefield Capital Management, LLC 346,300 6.99% 450 Seventh Avenue, Suite 509 New York, NY 10123 Randeep S. Grewal 782,500(2) 14.30% Chairman of the Board, Chief Executive Officer, and President 630 Fifth Avenue, Suite 1501 New York, NY 10111 Dr. Jan F. Holtrop 73,499(3) 1.47% Director Van Alkemadelaan 2596 AS The Hague The Netherlands George G. Andrews 95,250(4) 1.89% Director 7899 West Frost Drive Littleton, CO 80123 40 Name and Address of Beneficial Owner Common Stock(1) Percent of Class ------------------- --------------- ---------------- Kenton D. Miller 41,000(5) * Director 212 F. 25th Street Tulsa, OK 47114 Dai Vaughan 70,000(6) 1.39% Director 2536 Waterstone Way Marietta, GA 30062 Brent E. Stromberg 76,900(7) 1.53% VP Operations 2801B Santa Maria Way Santa Maria, CA 93455 Susan M. Whalen 45,000(8) * VP Asset Management 2801B Santa Maria Way Santa Maria, CA 93455 Richard R. Lembcke 76,575(9) 1.52% VP Business Development 2801B Santa Maria Way Santa Maria, CA 93455 Max A. Elghandour 30,000(10) * Chief Financial Officer 630 Fifth Avenue, Suite 1501 New York, NY 10111 All directors and officers as a group 1,290,724(11) 21.70% (9 persons) * Less than l% (1) Rule l3d-3 under the Securities Exchange Act of 1934 involving the determination of beneficial owners of securities, includes as beneficial owners of securities any person who directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise has, or shares, voting power and/or investment power with respect to such securities, and any person who has the right to acquire beneficial ownership of such security within sixty days, including through the exercise of any option, warrant or conversion of a security. (2) Includes options presently exercisable to acquire 520,000 shares of GREKA Energy common stock, and 262,500 shares of GREKA Energy common stock held individually by Mr. Grewal. (3) Includes options presently exercisable to acquire 50,000 shares of GREKA Energy common stock. (4) Includes options presently exercisable to acquire 90,000 shares of GREKA Energy common stock. (5) Consists of options presently exercisable to acquire 41,000 shares of GREKA Energy common stock. (6) Consists of options presently exercisable to acquire 70,000 shares of GREKA Energy common stock. 41 (7) Includes options presently exercisable to acquire 75,000 shares of GREKA Energy common stock. (8) Consists of options presently exercisable to acquire 45,000 shares of GREKA Energy common stock. (9) Includes options presently exercisable to acquire 75,000 shares of GREKA Energy common stock. (10) Includes options presently exercisable to acquire 30,000 shares of GREKA Energy common stock. (11) Includes options presently exercisable to acquire 996,000 shares of GREKA Energy common stock held by directors and executive officers of GREKA Energy. Item 13. Certain Relationships and Related Transactions During the last three fiscal years, there have been no material transactions between GREKA and any officer, director, nominee for election as director, or any shareholder owning greater than five percent (5%) of GREKA's outstanding shares, nor any member of the above referenced individuals' immediate family, except for options granted to and financing transactions with IPH (See Item 5 - "Market for Common Equity and Related Stockholder Matters"; Item 1 - "Description of Business, Financing & Debt Restructuring Activities", Mr. Grewal's restated employment agreement (See Item 11 - "Executive Compensation") and the Settlement Agreement and Release entered into with Capco dated August 17, 2000, and as set forth below. The Company had a non-interest bearing note receivable at December 31, 2000 from Randeep S. Grewal, the Company's Chairman of the Board and Chief Executive Officer of $750,000 relating to an exercise of stock options on December 26, 2000. This note was repaid on January 9, 2001. The Company had a non-interest bearing note receivable at December 31, 2001 from Randeep S. Grewal, the Company's Chairman of the Board and Chief Executive Officer of $500,000 which was all due and payable on April 30, 2002. This note has been repaid in full. It is GREKA's policy that any future material transactions between it and members of its management or their affiliates shall be on terms no less favorable than those available from unaffiliated third parties. Item 14. Controls and Procedures Our Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation within 90 days of the filing date of this report, that our disclosure controls and procedures are effective for gathering, analyzing and disclosing the information we are required to disclose in our reports filed under the Securities Exchange Act of 1934. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of the previously mentioned evaluation. 42 Part IV Item 15. Exhibits and Reports on Form 8-K. (a) Exhibits. The following exhibits are furnished as part of this report: Exhibit No. Exhibit Description ----------- ------------------- 3.1 Restated Articles of Incorporation of Horizontal Ventures (filed as Exhibit 3A to Horizontal Ventures' Quarterly Report on Form 10-QSB for the quarter ended June 30, 1998 (File No. 0-20760) and incorporated herein by reference) 3.2 Articles of Amendment to Articles of Incorporation effective March 22, 1999 (filed as Exhibit 3.1 to the Company's Current Report on Form 8-K dated March 15, 1999 and incorporated herein by reference) 3.3 ByLaws of Horizontal Ventures (incorporated by reference to Exhibit No. 3 to the Horizontal Ventures' Registration Statement (#33-24265-LA) 3.4 Amendment to Article II of the Bylaws of GREKA (filed as Exhibit 3.1 to the GREKA Report on Form 10-Q for the Quarter ended September 30, 1999 and incorporated by reference herein) 10.1 Amended and Restated Executive Employment Agreement dated November 3, 1999 among Randeep S. Grewal and GREKA (filed as Exhibit 10.2 to the GREKA Report on Form 10-Q for the quarter ended September 30, 1999 and incorporated by reference herein) 10.2 Rights Agreement dated November 3, 1999 (filed as Exhibit 10.4 to the GREKA Report on Form 10-Q for the quarter ended September 30, 1999 and incorporated by reference herein) 10.3 First Amended and Restated Loan and Security Agreement dated November 30, 1999 by and among GMAC Commercial Credit LLC, Greka Integrated, Inc., Saba Realty, Inc. and Santa Maria Refining Company (filed as Exhibit 10.1 to the GREKA Report on Form 8-K filed February 18, 2000 and incorporated by reference herein) 10.4 Letter Agreement dated December 13, 1999 by and among GMAC Commercial Credit LLC, Greka Integrated, Inc., Saba Realty, Inc. and Santa Maria Refining Company (filed as Exhibit 10.2 to the GREKA Report on Form 8-K filed February 18, 2000 and incorporated by reference herein) 10.5 Settlement Agreement and Release by and among GREKA and Randeep S. Grewal and Capco Resources, Ltd., Capco Energy, Inc., and Ilyas Chaudhary dated August 17, 2000 (filed as Exhibit 10.8 to the Post Effective Amendment No. 1 to the registration statement on Form S-2, file no. 333-45352, and incorporated by reference herein) 10.6 First Amendment To First Amended And Restated Loan And Security Agreement dated February 22, 2001 by and among GMAC Commercial Credit LLC, Greka Integrated, Inc., Saba Realty, Inc. and Santa Maria Refining Company (filed as Exhibit 10.30 to the GREKA Annual Report on Form 10-K for the fiscal year ended December 31, 2000 and incorporated by reference herein) 43 Exhibit No. Exhibit Description ----------- ------------------- 10.7 Loan Agreement dated as of March 1, 2001 among Greka AM, Inc. as borrower, the Company as guarantor, and the Bank of Texas, National Association (filed as Exhibit 10.31 to the GREKA Annual Report on Form 10-K for the fiscal year ended December 31, 2000 and incorporated by reference herein) 10.8 Amended and Restated Loan and Security Agreement between Greka AM, Inc. as borrower and International Publishing Holding, Inc. as Lender dated October 1, 2002 (filed as Exhibit 10.1 to the GREKA Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2002 and incorporated by reference herein) 10.9 Amendment No. 1 to Securities Purchase Agreement between GREKA Energy Corporation as borrower, certain of its affiliates as guarantors, and Guggenheim Investment Management, LLC as collateral agent dated October 28, 2002 (filed as Exhibit 10.2 to the GREKA Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2002 and incorporated by reference herein) 10.10 Stock Purchase Agreement between P.I. Holdings No. 3, Inc., P.I. Holdings No. 4, and the Company dated September 12, 2002; First Amendment thereto dated September 27, 2002; and Second Amendment thereto dated October 28, 2002* 10.11 Amendment No. 2 to Securities Purchase Agreement between GREKA Energy Corporation as borrower, certain of its affiliates as guarantors, and Guggenheim Investment Management, LLC as collateral agent dated March 11, 2003** 10.12 Note Purchase Agreement between GREKA AM, Inc. as borrower, certain of its affiliates as guarantors, and Guggenheim Investment Management, LLC as collateral agent dated March 11, 2003** 10.13 Amendment No. 3 to Securities Purchase Agreement between GREKA Energy Corporation as borrower, certain of its affiliates as guarantors, and Guggenheim Investment Management, LLC as collateral agent dated March 21, 2003** 21.1 Subsidiaries of GREKA** 23.1 Consent of Netherland, Sewell & Associates, Inc.** 23.2 Consent of Ryder-Scott Company Petroleum Consultants** 23.3 Consent of Deloitte & Touche LLP** * Request for confidentiality pending. ** Filed herewith. (b) Reports on Form 8-K. During the fourth quarter of 2002, GREKA filed no reports on Form 8-K. 44 GREKA ENERGY CORPORATION AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE Page ---- Consolidated Financial Statements of GREKA Energy Corporation Independent Auditors' Report........................................ F-2 Independent Auditors' Report (Predecessor Auditor) .................. F-3 Consolidated Balance Sheets as of December 31, 2002 and 2001......... F-4 Consolidated Statements of Operations for the years ended December 31, 2002, 2001, and 2000 ................................. F-5 Consolidated Statements of Stockholders' Equity for the years ended December 31, 2002, 2001, and 2000 ..................... F-6 Consolidated Statements of Cash Flows for the years ending December 31, 2002, 2001, and 2000 .......................... F-7 Notes to Consolidated Financial Statements........................... F-8 Schedule II - Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2002.. A-1 All other financial statement schedules have been omitted since they are either not required, are not applicable or the required information is included in the consolidated financial statements or the notes thereto. F-1 INDEPENDENT AUDITORS' REPORT ---------------------------- To the Board of Directors and Stockholders of Greka Energy Corporation: We have audited the accompanying consolidated balance sheets of Greka Energy Corporation and subsidiaries (the "Company") as of December 31, 2002 and 2001 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. Our audit also included the 2002 and 2001 financial statement schedule listed in the Index as Schedule II. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the 2002 and 2001 financial statements based on our audits. The consolidated statements of operations, stockholders' equity, and cash flows and financial statement schedules for the year ended December 31, 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and stated that such 2000 financial statement schedule, when considered in relation to the 2000 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein, in their report dated April 13, 2001, which also included an explanatory paragraph indicating that the Company, effective January 1, 2000, changed its accounting for inventory from the first in, first out method to the average cost method. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the 2002 and 2001 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the 2002 and 2001 financial statement schedules, when considered in relation to the 2002 and 2001 basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. /s/ Deloitte & Touche LLP March 27, 2003 New York, New York F-2 Greka Energy Corporation dismissed Arthur Andersen LLP on May 21, 2001, and subsequently engaged Deloitte & Touche LLP as its independent auditors. The predecessor auditors' report appearing below is a copy of Arthur Andersen LLP's previously issued opinion dated April 13, 2001. Since Greka Energy Corporation is unable to obtain a manually signed audit report, a copy of Arthur Andersen's LLP's most recently signed and dated report has been included to satisfy filing requirements, as permitted under Rule 2-02 (e) of Regulation S-X. Report of Independent Public Accountants To the Shareholders of GREKA Energy Corporation: We have audited the accompanying consolidated balance sheets of GREKA Energy Corporation (a Colorado corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of GREKA Energy Corporation and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States. As explained in Note 2 to the financial statements, effective January 1, 2000, the Company has changed its accounting for inventory from the first in, first out method to the average cost method. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. Schedule II - Valuation and Qualifying Accounts is presented for purposes of complying with the Securities and Exchange Commission's rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements, and in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ Arthur Andersen LLP New York, New York April 13, 2001 F-3

Year Ended December 31, ------------------------------------ 1998(1) 1999(1) 2000(1) -------- -------- -------- Production Data: Oil (MBbls) ............. 13 528 770 Gas (MMcf) .............. -- 862 1,807 Total (MBOE) .......... 13 685 1,099 Average Sales Price Data (Per Unit): BOE ..................... $ 6 $ 14.65 $ 22.14 Selected Data per BOE: Production costs(2) ..... $ 9 $ 6.27 $ 6.49 General and administrative ........ $ 119 $ 3.42 $ 5.79 Depletion, depreciation and amortization .......... $ 26 $ 2.90 $ 2.90

GREKA Energy Corporation Notes to Consolidated Financial Statements December 31, 2002 NOTE 1 - DESCRIPTION OF BUSINESS GREKA Energy Corporation, a Colorado corporation ("GREKA" or the "Company") is an independent integrated energy company. The Company's oil and gas production, exploration and development activities are concentrated in its properties in California where the Company also owns and operates an asphalt refinery. The Company supplies its asphalt refinery with equity oil, which is the crude oil the Company produces from its surrounding heavy crude oil reserves, and it also utilizes crude oil purchased from third party producers. GREKA believes that its vertically integrated operations reduces its exposure to material volatile swings in crude oil prices. Historically the Company has also engaged in oil and gas exploration, development and production from its properties in Louisiana, Texas and New Mexico which operation has substantially been sold as part of its strategic, internal reorganization. In addition, GREKA has interests in coalbed methane properties and production sharing contracts in China. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of presentation - The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in the accompanying consolidated financial statements. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant estimates involves the assessment of the amount of proved natural gas and oil reserves, the estimate of future development and plug and abandonment costs. Actual results could differ from those estimates. Effective December 31, 2000, the Company declared a 5% stock dividend for issuance of .05 share of common stock for each share of common stock issued and outstanding to holders of the Company's common stock as of December 31, 2000. The fair market value of the dividend has been reflected as a charge to retained earnings in the accompanying consolidated financial statements. The accompanying financial statements have been adjusted to reflect the additional shares issued in connection with this stock dividend as if such shares had been outstanding for all periods presented. Certain reclassifications have been made to prior year financial statements to conform to the current year presentation. Cash and cash equivalents - The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Fair value of financial instruments - The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, other current liabilities and notes payable, approximate fair value because of the short maturity of these items. These fair value estimates are subjective in nature and involve uncertainties and matters of significant judgment, and, therefore, cannot be determined with precision. Changes in assumptions could significantly affect these estimates. Accounts receivable - The Company provides an allowance for uncollectible receivables when it is determined that collection is doubtful. Substantially all of the Company's subsidiaries' trade receivables for 2002 and 2001 are from sales of asphalt and related products and oil and gas billings, including those to joint interest property owners. F-8 Inventories - Inventories are stated at the lower of cost or market. The Company's accounting method for inventory was changed from the first in, first out (FIFO) method to the weighted average cost method effective January 1, 2000. The weighted average cost method is preferable because the primary inventoriable cost at the refinery is crude oil for which the price can fluctuate significantly. The weighted average cost method balances the impact of short term fluctuations in crude oil pricing on the Company's refinery inventory levels. The Company recorded the effect of this change of $853,110 as a cumulative effect of a change in accounting principle as of January 1, 2000. Concentrations of credit risk - Substantially all of the Company's subsidiaries' accounts receivable are from companies engaged in the asphalt/paving and oil and gas businesses, and concentrated in the Western and Southern United States. Generally, the Company's subsidiaries do not require collateral for its accounts receivables. Four customers exceeded individually more than 10 percent of the Company's sales of North American refinery production during 2002, namely FAMM, Lawson, Union and Granite which accounted for approximately 18%, 20%, 20% and 18%, respectively, of such sales and approximately 2.6%, 22.6%, 5.8%, and 7.1%, respectively, of the related receivable balance as of December 31, 2002. Other than production from the Company's Integrated Operations Division which is transported to the Company's refinery, three customers exceeded individually more than 10 percent of the Company's sales of North American oil and gas production during 2002, namely Tosco, Adams Resources and Plains Marketing, L.P. which accounted for 51%, 12% and 15%, respectively, of such sales. Property and equipment - Property and equipment is stated at cost. The Company follows the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method, all costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Such costs include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. Sales, general and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions that involve a significant amount of reserves in a cost center. The proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. Fees from associated oil and gas exploration and development partnerships, if any, are credited to oil and gas property costs to the extent they do not represent reimbursement of Sales, general and administrative expenses currently charged to expense. Such costs can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead, or similar activities. Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as the Company's subsidiaries' capitalized oil and gas property costs are amortized. The Company's subsidiaries' properties are all onshore, and the Company expects that the salvage value of the tangible equipment will substantially offset any site restoration and dismantlement and abandonment costs. The provision for depreciation, depletion, and amortization of oil and gas properties is computed on the unit-of-production method. Under this method, the Company computes the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement and abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country by country basis for those countries with oil and gas production. The cost of unevaluated properties (approximately $5.0 million and $7.3 million at December 31, 2002 and 2001, respectively) not being amortized is assessed quarterly to determine whether the value has been impaired below the capitalized cost. Any impairment assessed is added to the cost of proved properties being amortized. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which the Company intends to commence such activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. The unamortized cost of oil and gas properties capitalized, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current prices, discounted at 10%, and the lower of cost or estimated fair value of unproved properties, adjusted for related income tax effects ("Ceiling Limitation"). F-9 The calculation of the Ceiling Limitation and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Depreciation for all other property and equipment is provided over estimated useful lives using the straight-line method of depreciation. Renewals and betterments are capitalized when incurred. Costs of maintenance and repairs that do not improve or extend asset lives are charged to expense as incurred. Environmental expenditures - If and when remediation of a property is probable and the related costs can be reasonably estimated, the environmentally related remediation costs will be expensed and recorded as liabilities. If recoveries of environmental costs from third parties are probable, a receivable will be recorded. Revenue recognition - Revenue from sale of oil, gas and asphalt production is recognized in the period in which title to the products is transferred, which is generally considered to have occurred upon delivery of the products. The related costs and expenses are recognized when incurred. Revenues from drilling operations are recognized in the accounting period, which corresponds with the performance of the service to the customer. Federal and State income taxes - The Company follows SFAS No. 109, "Accounting for Income Taxes," which accounts for income taxes using the liability method. Under SFAS No. 109, deferred income tax assets and liabilities are determined based on differences between the financial statement and tax bases of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. The primary differences between financial reporting and income tax reporting relate to the availability of net operating loss carryforwards, and the use of accelerated methods of depreciation for income tax purposes. A full valuation allowance is recorded against the Company's net deferred tax asset due to uncertainty regarding its realization as it is more likely than not that the deferred tax assets will not be realized. Earnings per share - Basic earnings(loss) per share has been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings (loss) per share is computed by considering the effect of outstanding options, warrants and other convertible securities. However, diluted earnings (loss) per share is the same as basic earnings per share in periods in which a loss has been incurred. The impact of a 5% stock dividend, which was effective on December 31, 2000, has been reflected in earnings (loss) per share for all periods presented. Comprehensive (loss) income - There were no other comprehensive (loss) income items for the years presented. Stock options issued to employees and directors - The Company follows the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"). SFAS No. 123 encourages, but does not require, companies to adopt a fair value based method for determining expense related to stock option compensation. The Company continues to account for stock based compensation for employees using the intrinsic value method as prescribed by Accounting Principles Board Opinion ("APB") No. 25, " Accounting for Stock Issued to Employees" and related Interpretations. Under APB Opinion No. 25, no compensation expense is recognized for employee option grants because the exercise price of the options granted to date has equaled the market price of the underlying shares on the date of grant (the "intrinsic value method"). F-10 Had compensation cost been determined consistent with SFAS No. 123, the Company's net (loss) income and (loss) earnings per share would have been adjusted to the following pro forma amounts:

~~Year Ended~~ December 31, ------------------------------------------------------ ~~1998~~2002 ~~1999~~2001 2000 --------------- -------------- -------------- ~~Gross(1)~~ Net (2Loss) ~~Gross~~Income as reported $ (110,082,509) ~~Net~~$ (27,613,544) ~~Gross~~$ 4,457,214 Deduct:total stock-based compensation Expense under fair value based method for all periods, net of tax -- (136,500) ~~Net~~(2142,390) -------- ------ -------- ------ -------- ------ ~~United~~Pro ~~States:~~Forma ~~Development~~Net ~~Wells~~(Loss) ~~Oil~~Income 3(10,082,509) (7,650,044) 4,314,824 Basic EPS as reported $ (2.311) --$ --(1.67) 5$ 51.00 ~~Gas~~Pro --Forma --Basic --EPS --$ --(2.11) --$ ~~Dry~~ (31.68) --$ --.96 --Diluted --EPS as reported $ (2.11) $ (1.67) $ .99 Pro Forma Diluted EPS $ (2.11) $ (1.68) $ .90

The fair value of each option granted in 2002, 2001, and 2000 is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: a) risk free interest rate ranging from 5% to 6.48%, b)expected volatility ranging from 59.2% to 64.2%, c) average time to exercise of 7 years, and d) expected dividend yield of zero. Stock options and warrants issued to non-employees - The Company follows the provisions of SFAS No. 123 with respect to transactions in which goods or services are the consideration received for the issuance of equity instruments. Under SFAS No. 123, these transactions, which mainly represent financing costs, shall be accounted for based on the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The Company has determined that the fair value of the equity instrument is the most reliable measure. The fair value of the equity instrument is determined based on the Black-Scholes Model for option pricing. Recent Accounting Pronouncements A summary of the recent accounting pronouncements, issued by the Financial Accounting Standards Board ("FASB"),that may affect the Company are presented below. SFAS No. 141, "Business Combinations," requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. SFAS No. 142, "Goodwill and Other Intangible Assets", addresses accounting for the acquisition of intangible assets and accounting for goodwill and other intangible assets after they have been initially recognized in the financial statements. The Company does not currently have goodwill or other similar intangible assets' therefore, the adoption of the new standard on January 1, 2002, did not have any material effect on its consolidated financial statements. F-11 SFAS No. 143, "Accounting for Asset Retirement Obligations," addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 became effective on January 1, 2003 and early adoption is encouraged. SFAS No. 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Currently, the Company includes estimated future costs of abandonment and dismantlement in its full cost amortization base and amortizes these costs as a component of its depletion expense. The Company is continuing to revise its calculation of the impact the new standard will have on the consolidated financial statements and the Company does not believe there will be a material impact to the consolidated financial statements. SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," became effective on January 1, 2002, and addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for the Long-Lived Assets to Be Disposed Of" and Accounting Principles Board ("ABP") Opinion No. 30, "Reporting the Results of Operations-Reporting the Effects of Disposal of Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 retains the fundamental provisions of SFAS No. 121 and expands the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The standard had no impact on the consolidated financial statements for the year ended December 31, 2002. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds the provisions of SFAS No. 4 that require companies to classify certain gains and losses from debt extinguishments as extraordinary items, eliminates the provisions of SFAS No. 44 regarding transition to the Motor Carrier Act of 1980 and amends the provisions of SFAS No. 13 to require that certain lease modifications be treated as sale leaseback transactions. The provisions of SFAS No. 145 related to classification of debt extinguishment are effective for fiscal years beginning after May 15, 2002. The provisions of SFAS No. 145 related to lease modifications are effective for transactions occurring after May 15, 2002. The Company early adopted the provision of SFAS No. 145, as permitted, with respect to the classification of gains or losses from debt extinguishment. In 2002, the Company recorded approximately $265,000 of gain on extinguishment of debt as "other income". In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for costs associated with the exit or disposal of an activity be recognized when the liability is incurred. This statement also established that fair value is the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. The FASB has issued SFAS No. 148 "Accounting for Stock-Based Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. As of December 31, 2002, the Company accounts for stock-based employee compensation in accordance with APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. F-12 In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees", which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of the Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. Under this Interpretation, at the inception of guarantees issued after December 31, 2002, the Company will record the fair value of the guarantee as a liability, with the offsetting entry being recorded based on the circumstances in which the guarantee was issued. The Company does not have any third party guarantees outstanding other than certain guarantees issued in connection with the Company's debt. Such debt is recorded on the consolidated balance sheet at December 31, 2002. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB 51". This Interpretation requires that the primary beneficiary in a variable interest entity consolidate the entity even if the primary beneficiary does not have a majority voting interest. The consolidation requirements of this Interpretation are required to be implemented for any variable interest entity created on or after January 31, 2003. In addition, the Interpretation requires disclosure of information regarding guarantees or exposures to loss relating to any variable interest entity existing prior to January 31, 2003 in financial statements issued after January 31, 2003. The Company does not believe that this Interpretation will have a material effect on its consolidated financial condition or results of operations. NOTE 3 - ACQUISITIONS AND DIVESTITURES Acquisitions ------------ In June 2002, a subsidiary of the Company acquired from Vintage Petroleum California, Inc. ("Vintage") all of Vintage's oil and gas producing properties and facilities in the Santa Maria Valley of central California for approximately $17.5 million in cash. These properties, now operated by the Company, consist of five fields and approximately 110 producing wells, encompassing approximately 8,000 acres of mineral interest and over 800 acres of real estate. Of the purchase price paid, $2.4 million was allocated to real estate and $15.1 million was allocated to oil & gas properties. In October 2002, the Company entered into a stock purchase agreement to acquire all outstanding shares of Windsor Energy US Corporation ("Windsor") and all interests in Rincon Island Limited Partnership ("Rincon"), a Texas limited partnership that owns and operates oil and gas producing properties and facilities located within the Rincon Island Field in central California. The properties cover approximately 1,700 mineral acres, including a 1-acre island connected to land by a 2,700' causeway containing the gas and oil pipelines and facilitating vehicular access. At closing, of the 56 wells on the property, 12 were producing at approximately 300 BOPD and 80 MCFD. The purchase price, which consisted of assumption of certain liabilities was allocated to current assets ($1.2 million), to oil & gas properties ($0.3 million), and to other assets ($3.5 million). Divestitures ------------ In April 2002, the Company sold its interest in the Manila Village Field located in Jefferson Parish, south Louisiana for approximately $55,000. In May 2002, the Company sold its interest in the Potash Field, Plaquemines Parish, Louisiana (the "Potash sale") for a contract price of approximately $20 million. F-13 In June 2002, the Company sold its 75% exploration interest in the Jatiluhur Block, West Java for a $4 million future production payment and a retained 5% overriding royalty interest in the Block. Pertamina, the Indonesian state-owned oil company, consented to the sale. As a result of an assessment of the status of development of this project based on current information available, management has determined that recovery of the future production payment is uncertain and, as such, has recorded an asset impairment charge of $2.7 million in the 2002 consolidated statement of operations. In September 2002, a subsidiary of the Company entered into certain real estate purchase and sale agreements and recognized a gain of $3.9 million on these transactions. Such gain is recorded within "Gain on sale of properties" in the 2002 consolidated statement of operations. In January 2003, the Company closed, as planned, the sale of its 355-acre limestone reserve located in Monroe County, Indiana for a contract price of $0.5 million. As of December 31, 2002, the carrying value of the limestone property has been written down by $3.2 million to $0.5 million in order to adjust the carrying value of the property to its fair value less cost to sell. Such write down is recorded within Impairment of long-lived assets in the 2002 consolidated statement of operations. This property is reflected as "Assets held for sale" as of December 31, 2002. NOTE 4 - PROPERTY AND EQUIPMENT A summary of the Company's subsidiaries' property and equipment as of December 31, 2002 and 2001 is as follows: 2002 2001 ------------- ------------- Investment in limestone property ............. -- $ 3,675,973 Oil and gas properties (Full cost method) .... $ 46,361,062 46,928,312 Unevaluated oil and gas properties ........... 5,014,703 7,347,113 Land and buildings ........................... 19,135,235 17,247,744 Plant and equipment .......................... 22,764,807 29,823,908 ------------- ------------- Total cost ................................... 93,275,807 105,023,050 Accumulated depreciation, depletion and amortization .......................... (14,407,101) (15,557,669) ------------- ------------- $ 78,868,706 $ 89,465,381 ============= ============= Depreciation, depletion and amortization charged against income was $3,244,847 in 2002, $5,578,899 in 2001, and $3,592,242 in 2000. Estimated useful lives are as follows: Refinery .............................................. 40 years Buildings ............................................. 20 to 40 years Transportation equipment .............................. 5 to 6 years Office and computer equipment ......................... 3 to 10 years F-14 NOTE 5 - (LOSS) EARNINGS PER SHARE Earnings (loss) per share for 2002, 2001, and 2000 was calculated as follows:

~~Oil~~2002 ~~Gas~~2001 ~~Total~~2000 ~~Gross~~------------ ~~Net~~------------ ~~Gross~~------------ Net ~~Gross~~(Loss) ~~Net~~Income ...................................... $(10,082,509) $ (7,613,544) $ 4,457,214 Income impact of assumed conversion of convertible debt ................................... -- --- 256,770 ----- ------- ------ ------ ------------ ~~United~~Net ~~States~~(loss) ~~625~~income ~~487~~plus 80impact 41of ~~705~~assumed ~~528~~conversion .... $(10,082,509) $ (7,613,544) $ 4,713,984 ============ ============ ============ Weighted Average Common Shares Outstanding ............. 4,767,566 4,555,255 4,475,985 Effect of Dilutive Securities - Employee stock options and warrants/(a)/ ............ -- -- 58,754 Convertible Debt .................................... -- -- 228,240 ------------ ------------ ------------ Weighted Average Shares plus impact of assumed conversion ............................... 4,767,566 4,555,255 4,762,979 ============ ============ ============ Basic (Loss) Earnings per Share ..................... $ (2.11) $ (1.67) $ 1.00 Diluted (Loss) Earnings per share ................... $ (2.11) $ (1.67) $ 0.99

(a) During 2002 and 2001, employee stock options and warrants totaled 95,535 and 230,000, respectively. These securities are not included in 2002 and 2001 Diluted Loss per Share calculation since the effect is antidilutive. NOTE 6 - INVENTORIES Inventories includes material, labor and manufacturing overhead costs. Due to the continuous manufacturing process, there is no significant work in process at any time. Inventories consisted of the following as of December 31: 2002 2001 ---------- ---------- Raw Materials ........................ $ 209,167 $ 632,651 Finished goods ....................... 1,154,339 1,163,869 ---------- ---------- Total ............................. $1,363,506 $1,796,520 ========== ========== F-15 NOTE 7 - COMMITMENTS AND CONTINGENCIES The Company and its subsidiaries lease office space, automobiles, computers, and other equipment under various leases. Aggregate commitments under these non-cancellable operating leases at December 31, 2002 were as follows: Year Ending December 31: Amount ------------------------ ------- 2003 216,000 2004 133,000 2005 4,000 2006 2,000 --------- Total $355,000 ======== Rent expense included in the accompanying consolidated statements of operations was $336,328, $266,666, and $274,341 in 2002, 2001, and 2000, respectively. In October 1994, the Company licensed certain directional drilling technology from BP Amoco, a major oil corporation. The license currently requires minimum annual payments of $15,000 per year or $1,639 per well drilled under the license, whichever is greater, and the amounts are adjusted periodically for inflation. The Company incurred license fees approximating $15,000 for each of the years ended December 31, 2002, 2001, and 2000. Semi-annual settlements are required under the license, and BP Amoco has the right to terminate the license for non-payment. In 1995, the Company's predecessor agreed to acquire an oil and gas interest in California on which the seller had drilled a number of non-producing oil wells. The acquisition agreement required that the Company's predecessor assume the obligation to abandon any wells that it did not return to production. A third party whose consent was required to transfer the property did not consent to the transfer. The third party is holding the seller responsible for all remediation. The Company believes it has no financial obligation to remediate this property because it was never the owner of the property, never produced any oil or gas from the property and was not associated with the site and the seller did not give the Company's predecessor any consideration to enter into the contract for the property. Since May 2000, the Company commenced remediation on the subject property as directed by a regulatory agency as operator of record. Notwithstanding its compliance in proceeding with any required remediation on seller's account, the Company is committed to hold the seller accountable for the required obligations of the property. Through December 31, 2002, the Company has remediated 37 of 72 wells and related facilities on the property for a cost of approximately $2.15 million. This amount is recorded as a long-term receivable, as the Company believes it is probable that such amount will be recoverable from the seller. The Company has had informal discussions with the seller, which to date have not produced positive results. Therefore, the Company intends to pursue formal litigation for recovery. Based on future developments with this litigation, it is reasonably possible that the Company's estimate of recovery and ultimate liability could change in the near term and such change could be material. One of GREKA's subsidiaries owns an asphalt refinery in Santa Maria, California, with which environmental remediation obligations are associated. There could be additional environmental issues which may require material remediation efforts in the future. There can be no assurance that material costs for remediation or other environmental compliance will not be incurred in the future. The occurrence of such environmental compliance costs could be materially adverse to the Company. No assurance can be given that the costs of closure of any of the Company's subsidiaries' other oil and gas properties would not have a material adverse effect on the Company. F-16 NOTE 8 - FEDERAL AND STATE INCOME TAXES The components of (loss) income before (benefit) provision for income taxes for the years ended December 31, 2002, 2001, and 2000 are as follows: 2002 2001 2000 ------------ ------------ ------------ United States .......... $(10,049,400) $ (7,577,044) $ 5,542,481 International .......... -- -- 129,807 ------------ ------------ ------------ $(10,049,400) $ (7,577,044) $ 5,672,288 ============ ============ ============ Components of the (benefit) provision for income taxes for the years ended December 31, 2002, 2001 and 2000 are as follows: 2002 2001 2000 -------- -------- -------- Current Federal ................... $ -- $ -- $ 93,787 State ..................... 33,109 36,500 268,177 -------- -------- -------- $ 33,109 $ 36,500 $361,964 Deferred Federal ................... -- -- -- State ..................... -- -- -- -------- -------- -------- -- -- -- -------- -------- -------- $ 33,109 $ 36,500 $361,964 ======== ======== ======== The following presents the reconciliation of the provision for income taxes to United States federal income taxes computed at the statutory rate for years ended December 31:

~~Developed~~2002 2001 2000 ------------ ------------ ------------ (Loss) Income before income taxes and cumulative effect of change in accounting principle ...... $(10,049,400) $ (7,577,044) $ 5,672,288 ============ ============ ============ (Benefit)Provision for income taxes at the statutory rate ................................ (3,517,290) (2,651,965) 1,985,300 State income tax (benefit) ~~Undeveloped~~provision, net of federal tax (benefit) provision ............... (457,247) (344,755) 268,177 Benefit from utilization of net operating losses for which a full valuation allowance was provided for in prior years ..... -- -- (1,985,300) Change in valuation allowance .......................... 1,504,018 360,585 -- Non-deductible losses .................................. 2,503,628 2,672,635 -- Other, net ............................................. -- -- 93,787 ------------ ------------ ------------ ~~Gross~~Provision ~~Net~~for ~~Gross~~income ~~Net~~taxes ~~United~~............................. ~~States~~$ 2133,~~070~~109 ~~16,180~~$ 1136,~~201~~500 8$ 361,~~025~~964 ======== ==== === ========= ============

F-17 The components of deferred tax assets and liabilities as of December 31, as follows: 2002 2001 ----------- ----------- Deferred Tax Assets: Depreciation and amortization .............. $ -- $ 1,102,642 Allowance for doubtful accounts ............ 189,664 183,228 Profit sharing plan ........................ 126,000 126,000 Net operating losses ....................... 7,900,810 8,050,390 Other ...................................... 502,359 502,359 ----------- ----------- Gross deferred tax assets .................. 8,718,833 9,964,619 Valuation allowance ........................ (8,306,241) (9,964,619) ----------- ----------- Deferred tax assets - net ........... 412,592 -- ----------- ----------- Deferred Tax Liability: Depreciation and amortization .............. $ 412,592 $ -- ----------- ----------- Deferred tax liability - net ........ 412,592 -- ----------- ----------- Net deferred tax asset (liability) ........... $ -- $ -- =========== =========== Significant net operating losses have been incurred in prior years, primarily by Petro Union, Horizontal Ventures and Saba, which generated net operating loss carry-forward credits. These net operating loss credits expire, if unused, as follows: Tax Year Expires In Approximate Amount ----------- ---------- ------------------ 1998 2018 $ 8,000,000 1999 2019 2,000,000 2001 2021 8,000,000 ------------ Total $ 18,000,000 ============ The Company's review of its available net operating loss carry-forward credits is ongoing. Upon completion of this review, additional net operating loss carry-forward credits may be identified. In accordance with Internal Revenue Service regulations, the use of the above net operating loss carry-forward credits related to acquired companies is subject to an annual limitation. As of March 28, 2003, the Company had not filed its December 31, 2001 Federal, state and local tax returns. The Company does not believe that it will be required to pay any interest and penalties related to the late filing. Currently, the Company is working to complete such filings in order to be in compliance. F-18 NOTE 9 - NOTES PAYABLE AND LONG-TERM DEBT: Notes payable and long-term debt consisted of the following at December 31, 2002 and 2001: 2002 2001 ----------- ----------- 9% convertible senior subordinated debentures due 2005 net of discount(a) ............................... $ 831,897 $ 2,527,088 15% convertible senior subordinated debentures due 2002(b) .................... -- 1,300,000 Loan agreement(c) ............................ 5,280,574 18,055,000 Loan agreement(d) ............................ 42,119,622 -- Loan agreement(e) ............................ 4,000,000 -- Note payable(f) .............................. -- 325,972 Note payable(g) .............................. -- 2,390,000 Notes payable(h) ............................. 1,545,000 -- Term and revolving loan agreement(i) ......... 3,306,947 18,256,811 Other notes and loans ........................ 253,496 277,567 ----------- ----------- $57,337,536 $43,132,438 Less current portion ......................... 9,672,914 33,993,043 ----------- ----------- Net long-term debt ........................... $47,664,622 $ 9,139,395 =========== =========== The minimum future principal payments due on long-term debt as of December 31, 2002 are as follows (in 000's) : 2003 $ 9,673 2004 42,120 2005 5,545 ------- Total $57,338 ======= (a) In June 2000, GREKA exchanged $3.3 million of Saba 9% senior subordinated convertible debentures for GREKA debentures. The GREKA debentures are convertible to Company common stock at the option of the holders of the debentures at any time prior to the due date of the debenture (December 31, 2005), unless previously redeemed. Upon the receipt of a duly executed notice of election to convert the GREKA debenture, the Company will convert the debenture to GREKA common stock based upon a per share conversion price equal to 95% of the average closing bid price of its common stock for 30 consecutive trading days ending one day prior to the receipt of the notice of election to convert except that the conversion price shall in no case be less than $8.50 per share nor greater than $12.50 per share. GREKA also has the right to redeem the GREKA debenture by providing 30 days written notice of its intent to redeem during which time the debenture holder may convert his or her debenture. During 2002, GREKA converted $0.04 million in principal of its 9% senior subordinated convertible debentures into 4,118 shares of GREKA common stock and paid $1.74 million in principal of debentures that had been redeemed, with a resulting debenture balance of $0.83 million in principal at December 31, 2002. (b) As of September 2002, GREKA satisfied in full its 15% subordinated convertible debentures by converting $1.26 million in principal plus accrued interest into 251,348 shares of GREKA common stock and paying $0.26 million in principal plus accrued interest. F-19 (c) In March 2001, one of GREKA's subsidiaries entered into a credit and guarantee agreement with the Bank of Texas, N.A. ("Bank of Texas"). The agreement provides that GREKA's subsidiary may borrow up to $75 million bearing interest at prime rate less 1/2 percent. GREKA closed a revolving credit line of $16 million with an initial advance of $13.2 million against the line secured by GREKA's subsidiary's interest in certain North American oil and gas properties. A portion of the proceeds were used to reduce the current debt of GREKA. In May 2002, Bank of Texas, N.A. was paid $12.5 million from the proceeds of the Potash sale. This loan was repaid in March 2003. (d) In June 2002, GREKA institutionally placed $30 million of a secured credit facility (of which $25 million of senior notes and $5 million of subordinated notes) that expire on June 26, 2004. The senior notes bear initial interest of 15% per year while the senior subordinated notes bear initial interest of 21% per year. Interests are payable on a monthly basis. The interest rates payable are adjusted downward based on the Company achieving certain financial targets and could result in a minimum interest of 11% and 17% for the senior and subordinated notes, respectively. The Company did not achieve these targets as of December 31, 2002. Both senior and subordinate notes bear an additional compounded interest of 6% per year, which is payable upon maturity. Out of the proceeds of the above financing, the Company paid $14.3 million to GMAC to retire its term loan and $12 million to acquire Vintage's Santa Maria assets. In October 2002, GREKA institutionally placed additional senior subordinated notes of $12.5 million, which accretes up to $14.5 million until maturity on June 26, 2004. These notes bear interest of 12.37% per year. Of the $12.5 million proceeds, GREKA did: i) pay off its outstanding debt to Vintage ($6 million); ii) pay off all but approximately $832,000 of its convertible debentures; iii) acquire $5.35 million worth of operational bonds related to the acquisition of Rincon and Windsor; and iv) applied the excess borrowings balance toward working capital and closing costs. The senior and the subordinated notes are secured by certain California oil and gas assets and real estate of GREKA's subsidiaries and all the shares of common stock of such subsidiaries owned by the Company. In connection with the issuance of the senior and subordinated notes above, the Company granted warrants to purchase an aggregate of 230,000 shares of common stock of the Company to the note holders and to the collateral agent who arranged for such financing. Holders of the warrants have the right to have the shares underlying the warrants registered. The Company has allocated the proceeds of debt securities between the debt and the warrants issued to note-holders based on relative fair values at the time of issuance in accordance with the provisions of APB Opinion No. 14, "Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants". The portion of the proceeds allocated to the warrants issued to note-holders ($789,732) has been accounted for as paid-in capital and as a reduction of the debt (debt discount). With respect to the warrants issued to the collateral agent, such warrants have been recorded as deferred financing costs at their estimated fair value at the date of issuance ($430,463), against additional paid-in capital. See Note 12. The senior and subordinated notes contain covenants which include: (i) certain profitability and leverage ratios; (ii) restrictions on assumptions of new indebtedness; (iii) restrictions on capital expenditures; and (iv)requirements of minimum crude run and crude oil production. As of December 31, 2002, the Company was in compliance with such covenants after considering the retroactive effects of the amendments made to the debt agreement in March 2003 (see Note 16). F-20 (e) In April 2002, GREKA closed a $5.1 million bridge facility to provide short-term liquidity during the implementation of GREKA's restructuring. In September 2002, the Company paid $1.1 million toward the $5.1 million bridge facility that closed in the second quarter of 2002. The payment was made from the sale proceeds of certain real estate owned by the Company. In October 2002, the $4 million balance of the $5.1 million bridge facility was transferred to IPH, and IPH cancelled the irrevocable standby letter of credit in the amount of $4 million that was arranged in favor of the initial creditor. In connection with IPH providing such irrevocable letter of credit, the Company granted to IPH options to purchase 400,000 shares of common stock of the Company. See Note 12. (f) In September 2002, GREKA paid in full the loan obligation to a bank as seller of a fee interest in property, thereby releasing the collateral against the fee interest. (g) In April 2002, GREKA paid in full the loan obligation in the principal amount of $2.4 million to IPH, thereby releasing collateral of all issued and outstanding shares of capital stock of a GREKA subsidiary. (h) In connection with its acquisition of Rincon and Windsor in October 2002, the Company assumed $1.5 million in promissory notes issued by Windsor. GREKA exchanged $772,500 of this debt for subordinated notes with 10% interest all due and payable January 15, 2005, provided that a prepayment by January 15, 2004 would waive any interest accrued. (i) In November 1999, the Company entered into a loan and security agreement with GMAC Commercial Credit LLC ("GMAC"). That agreement amends the loan and security agreement the parties entered into in April 1999. The November 1999 agreement increased from $11 million to $35 million the amount which GREKA's subsidiaries may borrow from GMAC. The financing consists of a term loan of $25 million and a revolving credit facility of $10 million. In February 2001, the credit facility with GMAC was increased providing for additional financing of up to $46 million by increasing the principal amount of the term loan to $36 million, and $10 million credit facility to fund working capital due November 30, 2005. In June 2002, the Company paid $14.3 million to GMAC to retire its term loan. The balance of working capital is secured by GREKA's subsidiaries' interests in the Company's refinery. The weighted average interest in 2002 was 10%. NOTE 10 - LITIGATION Bank of Texas, N.A. v. Greka AM, Inc. and GREKA Energy Corporation (Case No. 02-00771, 160th Judicial District Court of Dallas County, Texas, January 2002. In March 2003, the parties entered into a Settlement Agreement and Full Release resolving all outstanding issues. The settlement agreement provided full release of the Company upon repayment of the outstanding balance, which occurred in March 2003. People of State of California, et al. v. Greka SMV, Inc. (Case No. 1114292, Superior Court of State of California, County of Santa Barbara, Santa Maria Division, December 2002). Plaintiffs brought an action against one of GREKA's subsidiaries seeking damages of approximately $1 million for alleged statutory violations relating to a fire caused by a third party who, ignoring GREKA's instructions, entered GREKA's operations which were being conducted in accordance with common industry practice. GREKA has submitted this matter as an insurance claim, and plans to vigorously defend all claims asserted. The litigation is in its preliminary, pre-discovery stage. F-21 Union Oil Company of California, dba Unocal v. GREKA, et al. (Case No. 1125964, Superior Court of State of California, County of Santa Barbara, Santa Maria Division, December 2002). Plaintiff brought an action against GREKA and its subsidiaries seeking damages of approximately $6.25 million for alleged breach of contract claiming that, as successor-in-interest to Saba under the terms of the contract, the Company failed to abandon a certain number of wells or provide an acceptable abandonment plan, and failed to have in place instruments securing the abandonment. GREKA plans to vigorously defend all claims asserted. The litigation is in its preliminary, pre-discovery stage. From time to time, the Company and its subsidiaries are a named party in legal proceedings arising in the ordinary course of business. While the outcome of such proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the Company's financial condition or results of operations. NOTE 11 - EXECUTIVE OFFICER TRANSACTIONS On September 9, 1997, GREKA entered into a five-year employment agreement with Randeep S. Grewal. This agreement was amended on October 14, 1998, and on November 3, 1999, the Board of Directors adopted an amended and restated employment agreement for Mr. Grewal (the "Restated Agreement"). Under the terms of the Restated Agreement, Mr. Grewal's annual salary is $287,500 subject to an annual increase effective on the anniversary date. Mr. Grewal participates in GREKA's benefit plans and is entitled to bonuses and incentive compensation as determined by the Board of Directors of GREKA. The Restated Agreement also allows Mr. Grewal to receive an assignment of a 2% overriding royalty of all oil and gas properties of GREKA and its subsidiaries and to receive fringe benefits which include an automobile allowance of $1,000 per month. Under the original agreement, 31,500 shares of GREKA common stock were issued to Mr. Grewal. The Company had a $750,000 note receivable at December 31, 2000 from an officer of the Company relating to an exercise of stock options on December 26, 2000. This note was repaid on January 9, 2001. The Company had a $500,000 note receivable at December 31, 2001 from Randeep S. Grewal, the Company's Chairman of the Board and Chief Executive Officer, which was repaid in April, 2002. NOTE 12 - STOCK OPTIONS AND WARRANTS Stock Options issued to employees and directors At December 31, 2002, 2001, and 2000, GREKA had outstanding 1.4 million of authorized options to acquire shares of common stock of GREKA, of which 1,025,000 were granted in 2000 at an exercise price of $8.625 to employees and directors of the Company. A total of 164,000 options have terminated through attrition and 178,000 options were exercised during 2000, leaving the total option grants outstanding as of December 31, 2000 at 1,058,000 options. Management has determined not to adjust the exercise price or the number of employee options granted or available for grant not withstanding the 5% stock dividend issued during January 2001. During 2001, 113,000 options were granted at exercise prices of $12.50 (68,000 options) and $11.32 (45,000 options) to employees and directors of the Company. A total of 24,000 options have terminated through attrition and 39,000 options have been exercised, leaving the total option grants outstanding as of December 31, 2001 at 1,108,000 options. F-22 No options were granted or exercised in 2002, and a total of 2,000 options terminated through attrition leaving the total options grants outstanding as of December 31, 2002 at 1,106,000 options. A summary of the outstanding stock options issued to employees and directors follows:

~~Year~~2002 ~~Ended~~2001 ~~December~~2000 ~~31,~~ ---------- -------- -------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price --------- ~~1998 1999 2000~~ ---------- --------- -------- ~~Average~~------ ~~sales~~-------- ~~price~~Options ~~per~~outstanding, ~~BOE:~~January ~~Integrated~~1 ~~Ops~~ ................~~....~~ 1,108,000 $ 68.84 1,058,000 $ 108.8254 375,000 $ 186.6393 ~~E&P~~Options ~~Americas~~granted .............~~.........~~ -- 17-- 113,000 12.1403 251,025,000 8.2763 ~~Combined~~Options exercised ........... -- -- (39,000) (8.23) (178,000 (5.17) Options terminated .......... (2,000) (8...63) 6(24,000) 13(11.8685) 22(164,000) (8.1463) ~~Average~~--------- ~~production~~---------- ~~cost~~--------- ~~per~~------ ~~BOE:~~------- ~~Integrated~~----- ~~Ops~~Options outstanding, December 31 ..............~~......~~ 1,106,000 $ 98.84 1,108,000 $ 8.7484 1,058,000 $ 58.9154 ~~E&P~~Exercisable ~~Americas~~at year end ................. 1,056,000 $ 8.70 1,037,000 $ 9.23 222,000 $ 8...26 The following table summmarizes information about stock options outstanding, at December 31, 2002: Options Outstanding Options Exercisable ------------------- 5-------------------- Remaining Exercise Number of Contractual Number of Exercise Price Shares Life Shares Price -------- --------- ----------- --------- -------- $ 7.8075 5,000 6.782 ~~Combined~~years 5,000 $ 7.75 $ 8.25 163,000 5.8 years 163,000 $ 8.25 $ 8.63 845,000 7.1 years 835,000 $ 8.63 $ 11.32 45,000 8.3 years 15,000 $ 11.32 $ 12.50 48,000 8.1 years 38,000 $ 12.50 --------- --------- $ 8.84 1,106,000 7.3 years 1,056,000 $ 8.70 ========= ========= Stock Warrants and Options issued to non-employees A summary of the stock warrants and options issued to non-employees by the Company during 2002 follows: Number of Stock Warrants/ Options Effective Expiration Number of Stock Warrants/ Granted Option Price Date Date Options Exercised in 2002 --------- ------------ ---------------- ----------------- ------------------ 200,000 $6.00 April 1, 2002 September 30, 2003 0 200,000 $6.~~........~~50 9April 71, 2002 September 30, 2003 0 150,000 $0.4701 6June 26, 2002 June 26, 2012 0 80,000 $0.3701 October 28, 2002 October 28, 2012 0

F-23 The Company follows the provisions of SFAS No. 123 with respect to transactions in which goods or services are the consideration received for the issuance of equity instruments. Under SFAS No. 123, these transactions, which mainly represent financing costs, shall be accounted for based on the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The Company has determined that the fair value of the equity instrument is the most reliable measure. The fair value of the equity instrument was determined based on the Black-Scholes Model for option pricing. The Company has recorded the fair values of stock warrants issued to a collateral agent and of the options issued to IPH at their respective fair values at the dates of grant as deferred financing costs in the consolidated balance sheet as of December 31, 2002 (against additional paid in capital). Such costs are being amortized over the period of the underlying financing. The unamortized balance of such costs as of December 31, 2002 is $0.6 million and is included within other assets in the consolidated balance sheet. The fair value of options and warrants granted is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: a) risk free interest rate ranging from 5% to 6.48%, b)expected volatility of 53.4% c) average time to exercise of 1.2 to 10 years, and d) expected dividend yield of zero. NOTE 13 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Presented below is a summary of the changes in estimated domestic reserves of the Company for the years ended December 31:

~~Votes~~Proved ~~For~~developed ~~Votes~~and ~~Withheld~~undeveloped reserves 2002 2001 2000 ----------------------- ----------------------- ~~George~~----------------------- GOil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf) ---------- ---------- ---------- ---------- ---------- ---------- Balance beginning of the year ........... ~~Andrews~~10,051,892 19,381,523 12,012,060 20,074,566 10,531,706 17,598,296 Production .............................. (738,923) (836,847) (837,664) (1,773,827) (770,007) (1,806,764) Acquisitions of reserves in place ....... 15,885,508 7,214,225 -- -- -- -- Sale of reserves in place ............... (1,762,798) (13,654,797) (450,292) (1,133,088) -- -- Revisions of previous estimates ......... 3,~~014~~134,~~997~~732 35( 281,~~784~~560) Dr(672,212) 2,213,872 2,250,361 4,283,034 ---------- ---------- ---------- ---------- ---------- ---------- Balance end of the year ................. ~~Jan~~26,570,511 F11,822,544 10,051,892 19,381,523 12,012,060 20,074,566 Balance proved developed producing....... ~~Holtrop~~11,671,515 1,929,293 4,310,391 2,206,108 7,059,487 5,183,649 F-24 Capitalized costs 2002 2001 2000 ------------ ----------- ----------- Proved oil and gas properties (domestic) $ 46,361,062 $ 46,928,312 $31,318,933 Proved oil and gas properties (international) -- -- -- Unproved oil and gas properties (domestic) 3,~~018~~036,~~890~~065 3,036,065 4,656,659 Unproved oil and gas properties (international) 1,978,638 4,311,048 2,862,577 ------------ ------------ ----------- 51,375,766 54,275,425 38,838,169 Less accumulated depreciation, depletion and amortization (13,508,444) (15,257,669) (9,970,686) ------------ ------------ ----------- Net investment in oil and gas properties $ 37,867,322 $ 39,017,756 $28,867,483 ============ ============ =========== Results of Operations 2002 2001 2000 ----------- ----------- ----------- Oil and gas sales - Third party $ 5,887,136 $14,151,828 $14,673,501 Oil and gas sales - Affiliates 13,902,216 8,541,481 9,927,023 ----------- ----------- ----------- Total oil and gas sales 19,789,352 22,693,309 24,600,524 Production cost 8,161,640 8,976,720 6,057,571 Depreciation, depletion and amortization 2,860,907 5,050,189 3,024,801 ----------- ----------- ----------- Net income from Operations $ 8,746,209 $ 8,666,400 $15,518,152 =========== =========== =========== Depreciation, depletion and amortization rate per BOE $ 3.12 $ 4.34 $ 2.90 =========== =========== =========== Average production cost per BOE $ 4.90 $ 7.87 $ 5.51 =========== =========== =========== SFAS No. 69, "Disclosures About Oil and Gas Producing Activities," prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying benchmark prices and costs, including transportation and basis differential, in effect at year-end. Estimated future income taxes are computed using current statutory income tax rates, including consideration for estimated future statutory depletion and alternative fuels tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves, nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. F-25 The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS No. 69. Standardized measure of discounted future net cash flows 2002 2001 2000 ------------ ------------- ------------- Future cash flows $658,391,331 $197,238,400 $ 421,837,100 Future cost: Development cost (58,801,000) (26,749,700) (28,604,800) Production cost (268,991,259) (85,275,400) (116,726,900) ------------ ------------- ------------- Future net cash flows before income taxes 330,599,072 85,213,300 276,505,400 Future income taxes (115,709,675) (18,966,265) (92,590,000) ------------ ------------- ------------- Future net cash flows 214,889,397 66,247,035 183,915,400 10% annual discount for future cash flows (99,459,750) (28,595,600) (74,914,260) ------------ ------------- ------------- Standardized measure of discounted future cash flows, end of year(a) $115,429,647 $ 37,651,435 $ 109,001,140 ============ ============= ============= The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, are as follows: Changes in Standardized Future Cash Flows 2002 2001 2000 ------------- ------------- ------------- Beginning of year $ 37,651,435 $ 109,001,140 $ 46,255,189 Sales of Oil and Gas, net of production cost (11,627,712) (14,634,393) (19,431,000) Net changes in prices and production cost (92,537,015) (135,620,827) 116,861,306 Changes in development cost (32,~~468~~051,300) (5,186,100) (4,495,100) Revision of previous quantity estimates includes purchase and sale of reserves in place 242,661,269 (30,102,209) 67,613,989 Accreciation of discount 3,765,144 10,900,114 4,364,766 Net change in income taxes (96,743,410) 73,623,735 (56,874,370) Net changes in production rates, timing and other 64,311,236 29,669,975 (45,293,640) ------------- ------------- ------------- Standardized measure of discounted future cash flows $ 115,429,647 $ 37,651,435 $ 109,001,140 ============= ============= ============= Costs incurred in oil and gas property acquisition, exploration and development activities 2002 2001 2000 ------------ ------------ ------------ USA Proved and unproved property acquisition $15,348,248 $ 1,856,302 $ 133,359 Exploration -- -- -- Development 8,587,968 17,995,879 5,255,734 ----------- ----------- ----------- Total Cost Incurred 23,936,216 19,852,181 5,389,093 International Proved and unproved property acquisition 412,804 999,026 1,192,554 Exploration -- -- -- Development -- -- -- ----------- ----------- ----------- Total Cost Incurred 412,804 999,026 1,192,554 ----------- ----------- ----------- Total Company $24,349,020 $20,851,207 $ 6,581,647 =========== =========== ===========

F-26 NOTE 14 - CONDENSED QUARTERLY FINANCIAL DATA (UNAUDITED) During the second quarter of 2002, the Company recorded a gain of $3.1 million on the sale of the Potash Field, Plaquemines Parish, Louisiana based on the significance of the reserves sold. After completion of the year-end reserve analysis by independent reservoir engineers that resulted in a 110% increase in proved reserves at December 31, 2002 versus December 31, 2001, the Company determined the Potash sale did not significantly alter the relationship between capitalized costs and proved reserves. As a result, in the fourth quarter, the Company deferred the gain on sale and reduced its oil and gas capitalized costs by $3.1 million.

~~Bid~~Second ~~Low~~Quarter ~~High~~------------------------------ As First Previously As Third Fourth Quarter ~~Ended~~Reported ~~March~~Restated ~~31,~~Quarter ~~1999~~Quarter ~~4.875~~2002 ~~10.500~~------------ ~~June~~------------ 30------------ ------------ ------------ Revenues $ 4,403,733 ~~1999~~$ ~~6.375~~8,261,888 ~~9.125~~$ ~~September~~8,261,888 30$ 8,328,370 ~~1999~~$ 7~~.000~~,916,854 ~~13.500~~Operating ~~December~~Income 31(loss) (925,157) ~~1999~~1,424,406 71424,406 1,959,599 (4,235,456) Net Income (loss) (2,073,662) 2,795,063 (347,863) 166,749 (10,970,659) Basic and Diluted earning per common share: Net Income (loss) $ (0.~~500~~44) 12$ 0.~~000~~59 ~~March~~$ ~~31,~~(0.07) ~~2000~~$ 80.~~563~~03 9$ (0.~~500~~98) ~~June~~First 30Second Third Fourth Quarter Quarter Quarter Quarter --------- ----------- ----------- ------------ 2001 Revenues $ 6,989,830 ~~2000~~$11,622,892 ~~8.625~~$13,311,897 $ 8~~.813~~,830,663 ~~September~~Operating 30Income (loss) 1,240,032 ~~2000~~2,645,672 ~~14.375~~1,403,027 ~~15.688~~(3,168,469) ~~December~~Net 31Income (loss) 1,018,138 ~~2000~~1,813,162 ~~12.750~~2,713,742 (13,158,586) Basic and Diluted earning per common share: Net Income (loss) $0.~~438~~21 $0.37 $0.57 $(2.89)

NOTE 15 - EMPLOYEE BENEFIT PLANS Retirement Plan The Company sponsors a defined contribution retirement savings plan ("401(k) Plan") to assist all eligible U.S. employees in providing for retirement or other future financial needs. We currently provide matching contributions equal to 50% of each employee's contribution, subject to a maximum of 8% of their eligible contribution. In 2002, 2001 and 2000 the company contributed approximately $63,000, $55,000 and $53,000, respectively. Net Profit Sharing Plan The Company has a net profit sharing plan ("NPSP") for employees that fulfill certain qualification requirements. The NPSP provides for an equal disbursement normally of 10% of the Company's pretax income, excluding extraordinary gains. Such disbursement is planned to follow the filing of the annual audited financial statements of the Company. However, the NPSP could be suspended, increased or otherwise amended at the discretion of the Board of Directors for any specific year. In 2002, 2001 and 2000 the Company expensed approximately $300,000, $300,000 and $500,000, respectively in connection with its NPSP. F-27 NOTE 16 - SUBSEQUENT EVENTS Coalbed Methane Exploration Prospect, Jiangxi, Shanxi and Anhui Provinces, China. In January 2003, GREKA's wholly-owned subsidiary signed at the Great Hall of the People in China four Production Sharing Contracts PSCs with CUCBM for the exploitation of CBM resources in the Shanxi and Anhui Provinces. Considering the previously signed PSC for the Fengcheng Block in the Jiangxi Province, GREKA is now party to and operator under five, 30-year PSC's for CBM exploitation in China within two development and three exploration blocks. The combined total contract area is approximately 6,600 square kilometers (1.7 million acres) with average coalbed thickness of 16.5 feet and potential reserves of 34.5 Tcf, as estimated by CUCBM. Greka has a 60% working interest in all PSC's other than the Fengcheng Block in which it has a 49% working interest. The remaining working interest is owned by CUCBM. In March 2003, the Company amended, with certain retrospective effects, the terms of its loan agreement (see Note 9 -(d)), and it borrowed additional $20 million through the same collateral agent by issuing 2-years promissory notes. From these proceeds, the Company paid $4.7 million to Bank of Texas and $4.1 million to IPH to retire their respective loans, and the balance, in addition to closing costs and working capital, will fund a portion of the Company's $15 million capital expenditure program for 2003. Of the $20 million, $13.5 million bears interest at a variable rate of Libor + 6.25% or 8.25%, whichever is greater, while the balance $6.5 million bears interest at a fixed rate of 9.25%. The Company paid a 4.25% closing fee, and the placement resulted in increase by approximately $10 million to the Company's total debt. F-28 Greka Energy Corporation and subsidiaries Schedule II - Valuation and qualifying accounts(a) For Each of the Three Years Ended December 31, 2002 Balance at Charged to Charged to Balance Beginning of costs and other at End of Year Period expenses accounts Deductions Period ---- ------------ ---------- ---------- ---------- ---------- 2002 $ 436,258 $ 15,323 $ -- $ -- $ 451,581 2001 $ 827,144 $ -- $ 390,886(b) $ -- $ 436,258 2000 $1,343,852 $153,457 $ 363,251 $ -- $ 827,144 (a) The schedule presents information related to the allowance for doubtful accounts. (b) Write-off of individual accounts receivables. A-1 SIGNATURES In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. GREKA ENERGY CORPORATION Dated: April 10, 2003 By: /s/ Randeep S. Grewal ---------------------------------------- Randeep S. Grewal, Chairman of the Board and Chief Executive Officer In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date --------- ----- ---- /s/ Randeep S. Grewal ------------------------ Randeep S. Grewal Chairman of the Board of April 10, 2003 Directors and Chief Executive Officer (Principal Executive Officer) /s/ Max A. Elghandour ------------------------ Max A. Elghandour Chief Financial Officer April 10, 2003 and Principal Accounting Officer) /s/ Dr. Jan F. Holtrop ------------------------ Dr. Jan F. Holtrop Director April 10, 2003 /s/ Dai Vaughan ------------------------ Dai Vaughan Director April 10, 2003 /s/ Kenton D. Miller ------------------------ Kenton D. Miller Director April 10, 2003 CERTIFICATIONS I, Randeep S. Grewal, certify that: 1. I have reviewed this annual report on Form 10-K of Greka Energy Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Randeep S. Grewal ------------------------------------------ Randeep S. Grewal, Chief Executive Officer April 10, 2003 CERTIFICATIONS I, Max A. Elghandour, certify that: 1. I have reviewed this annual report on Form 10-K of Gerka Energy Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Max A. Elghandour ------------------------------------------ Max A. Elghandour, Chief Financial Officer April 10, 2003 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each undersigned officer of Greka Energy Corporation (the "Company"), hereby certifies to such officer's knowledge, that the Company's Annual Report on Form 10-K for the period ended December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Randeep S. Grewal ------------------------------------------ Randeep S. Grewal, Chief Executive Officer April 10, 2003 /s/ Max A. Elghandour ------------------------------------------ Max A. Elghandour, Chief Financial Officer April 10, 2003

Years Ended December 31, ------------------------------------------------------- 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- (In thousands, except per share data) Income Statement Data: Sales .............................................. $ 49,067 $ 29,138 $ 146 $ 212 $ 604 Production and Product Costs ....................... $ 25,200 $ 17,821 $ 121 $ 248 $ 367 General and administrative ......................... $ 6,699 $ 3,205 $ 1,542 $ 756 $ 575 Depletion, depreciation & amortization ..................................... $ 3,592 $ 3,024 $ 333 $ 24 $ 19 Other operating expenses ........................... $ 2,377 $ -- $ -- $ -- $ -- Interest Expense ................................... $ 4,535 $ 1,860 $ 32 $ 25 $ 35 Other Income(Expense) Net .......................... $ (991) $ (1,696) $ (526) $ (34) $ 15 Minority Interest .................................. $ -- $ 20 $ -- $ -- $ -- Income tax (expense) benefit ....................... $ (362) $ (46) $ -- $ -- $ -- Equity in Earnings/Loss of Saba (pre-acquisition) ................................ $ -- $ 569 $ 586 $ -- $ -- Cumulative effect of change in accounting .......... $ 853 $ -- $ -- $ -- $ -- Net income(loss) ................................... $ 4,457 $ 3,367 $ (5,548) $ (851) $ (377) Income (loss) per common share: Basic net income(loss) per share ................... $ 1.05 $ 0.84 $ (3.42) $ (1.44) $ (4.70) Cash dividend per share ............................ $ -- $ -- $ -- $ -- $ -- Basic weighted average common shares outstanding ............................... 4,263 4,003 1,621 591 80 Diluted weighted average common shares outstanding ............................... 4,550 4,575 1,621 591 80 Balance Sheet Data (end of period): Working Capital .................................... $ (2,663) $(14,176) $ (1,828) $ 3,133 $ 276 Net property and equipment ......................... $ 77,182 $ 70,287 $ 926 $ 6,795 $ 735 Total assets ....................................... $ 98,813 $ 84,214 $ 20,807 $ 10,803 $ 901 Long-term obligations .............................. $ 28,207 $ 15,696 $ 53 $ 77 $ 541 Total stockholders' equity ......................... $ 40,211 $ 33,378 $ 18,505 $ 9,095 $ (10)

Name Since Age Positions --------------------- --- --------------------------------------- Randeep S. Grewal 37 Chairman of the Board, Chief Executive September 1997 Officer and President, Class A Director Dr. Jan F. Holtrop 66 Class B Director September 1997 George G. Andrews 76 Class B Director July 1998 Dai Vaughan 62 Class C Director March 1999 Kenton D. Miller 48 Class C Director October 2000

Annual Compensation Long Term Compensation ---------------------------- ----------------------------- Restricted Securities Name and principal stock awards underlying All other position Year Salary($) Bonus($)(1) ($) options/SARS compensation ------------------ ---- --------- ----------- ------------ ------------ ------------- Randeep S. Grewal, 2000 $290,269 -- -- 410,000 $12,000(3) Chairman and Chief 1999 $248,400 -- -- -- $12,000(3) Executive Officer 1998 $120,000 -- $367,500(2) 110,000 $ 4,200(3)

Number of Percent of total Securities options/SARS Grant Underlying granted to Exercise or Date Options/SARS employees in base price Expiration Present Name granted(#) fiscal year ($/Sh) date Value ----------------- ------------ ---------------- ----------- ---------- ------- Randeep S. Grewal 410,000 40% $8.625 1/30/10 11.0038(2)

Value of Number of unexercised Shares unexercised in-the-money acquired options/SARS options/SARS on Value at FY-end(#) at FY-end($) exercise realized exercisable/ exercisable/ Name (#) ($) unexercisable unexercisable ----------------- -------- -------- ------------- ------------- Randeep S. Grewal 150,000 $1,331,250 120,000/400,000 $626,250/$1,950,000

1997 1999 Name Stock Option Plan(1) Stock Option Plan(2) -------------- -------------------- -------------------- George G. Andrews 5,000 60,000 Dai Vaughan 5,000 60,000 Jan F. Holtrop 5,000 50,000

Name and Address of Beneficial Owner Common Stock(1) Percent of Class ------------------- --------------- ---------------- Capco Resources Ltd 296,791(2) 6.53% 2922 E. Chapman Ave., Suite 202 Orange, CA 92869 International Publishing Holding s.a. 381,057 8.38% Postbus 84019 2508 AA The Hague The Netherlands Randeep S. Grewal 570,000(3) 11.71% Chairman of the Board, Chief Executive Officer, and President 10815 Briar Forest Drive Houston, TX 77042 Dr. Jan F. Holtrop 45,000(4) * Director Van Alkemadelaan 2596 AS The Hague The Netherlands George G. Andrews 65,000(5) 1.41 Director 7899 West Frost Drive Littleton, CO 80123 Dai Vaughan 44,000(6) * Director 2536 Waterstone Way Marietta, GA 30062 Kenton D. Miller 15,000(7) * Director 212 E. 25th Street Tulsa, OK 47114 All directors and officers as a group (5 persons) 739,000 14.72%

Page Financial Statements of GREKA Energy Corporation Report of Independent Public Accountants.............................F-2 Consolidated Balance Sheets as of December 31, 2000 and 1999.........F-3 Consolidated Statements of Operations for each of the three years ended December 31, 2000 ...............................F-4 Consolidated Statements of Stockholders' Equity for each of the three years ended December 31, 2000 ....................... F-5 Consolidated Statements of Cash Flows for each of the three years ended December 31, 2000 .....................................F-6 Notes to Consolidated Financial Statements...........................F-7 Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 2000........................F-23

Current Assets 2000 1999 ------------ ------------ Cash and cash equivalents .................................... $ 4,837,699 $ 97,319 Restricted cash .............................................. -- 1,000,000 Accounts receivable trade, net of allowance for doubtful accounts of $827,144 (2000) and $1,343,825 (1999) ...................................... 5,951,051 4,681,823 Inventories .................................................. 3,814,992 3,292,380 Other current assets ......................................... 5,160,062 2,912,451 ------------ ------------ Total Current Assets ................................ 19,763,804 11,983,973 ------------ ------------ Property and Equipment Investment in limestone property, at cost .................... 3,675,973 3,675,973 Oil and gas properties (full cost method) .................... 38,838,169 29,653,061 Land ......................................................... 17,247,744 17,210,814 Plant and equipment .......................................... 27,398,506 26,875,661 ------------ ------------ 87,160,392 77,415,509 Less accumulated depreciation, depletion and amortization ............................................... (9,978,770) (7,128,995) ------------ ------------ Property and Equipment Net ........................................... 77,181,622 70,286,514 Other Assets ......................................................... 1,867,859 1,943,196 ------------ ------------ $ 98,813,285 $ 84,213,683 ============ ============

Current Liabilities 2000 1999 ------------ ------------ Accounts payable and accrued expenses ........................ $ 13,742,245 8,235,627 Current maturities of long term notes and notes payable ...... 8,580,110 13,173,296 Short term borrowing ......................................... 105,000 4,750,685 ------------ ------------ Total Current Liabilities ........................... 22,427,355 26,159,608 Long term debt, net of current portion ............................... 28,206,771 15,695,825 Other Liabilities .................................................... 7,967,941 8,979,927 Commitments and Contingent Liabilities Stockholders' Equity Common Stock, no par value, 50,000,000 shares authorized, 4,523,273 (2000) 4,556,937 (1999) shares issued and outstanding .............................. 42,544,242 37,261,043 Accumulated comprehensive income ............................. -- (19,243) Accumulated earnings (deficit) ............................... (2,333,324) (3,863,477) ------------ ------------ Total Stockholders' Equity ................................... 40,211,218 33,378,323 ------------ ------------ $ 98,813,285 84,213,683 ============ ============

2000 1999 1998 ------------ ------------ ------------ Revenues ............................................................... $ 49,067,140 $ 29,137,810 $ 145,813 ------------ ------------ ------------ Costs and Expenses Operating Costs ................................................ 25,199,620 17,820,620 121,016 General and Administration ..................................... 6,699,275 3,205,276 1,541,789 Net Profit Sharing Plan ........................................ 495,246 -- -- Depreciation, depletion and amortization ....................... 3,592,242 3,023,783 333,468 Other expenses ................................................. 1,881,856 -- -- Writedown of oil and gas properties ............................ -- -- 3,171,485 ------------ ------------ ------------ Total Costs and expenses ............................................... 37,868,219 24,049,679 5,167,758 ------------ ------------ ------------ Operating Income (loss) ................................................ 11,198,901 5,088,131 (5,021,945) Other income (expense) Equity in loss of Saba ......................................... -- (568,751) (586,020) Interest income ................................................ -- -- 83,242 Interest expense ............................................... (4,535,174) (1,859,688) (32,145) Loss on sale of Canadian properties ............................ (991,439) -- -- Other, net ..................................................... -- 732,723 9,223 ------------ ------------ ------------ Other Income (expense), net ........................... (5,526,613) (1,695,716) (525,700) Minority Interest in loss of consolidated subsidiary ..................................................... -- 20,617 -- ------------ ------------ ------------ Income (loss) before income taxes and accounting changes ............................................. 5,672,288 3,413,032 (5,547,645) Provision for income tax ............................................... 361,964 46,000 -- Cumulative affect of change in accounting for inventory ................ 853,109 -- -- ------------ ------------ ------------ Net Income (Loss) ...................................................... 4,457,214 $ 3,367,032 $ (5,547,645) ------------ ------------ ------------ Other Comprehensive (Loss) ............................................. -- (19,243) -- ------------ ------------ ------------ Comprehensive Income (Loss) ............................................ 4,457,214 $ 3,347,789 $ (5,547,645) ============ ============ ============ Net Income (Loss) per Share - Basic .................................... $ 1.05 $ 0.84 $ (3.42) ============ ============ ============ Net Income (Loss) per Share - Diluted .................................. $ 1.04 $ 0.79 $ (3.42) ============ ============ ============ Weighted average number of shares outstanding - Basic .................. 4,262,843 4,002,917 1,621,483 ============ ============ ============ Weighted average number of shares outstanding - Diluted ................ 4,549,692 4,574,348 1,621,483 ============ ============ ============

Accumulated Common Stock (Deficit) Shares Amount Earnings Total ------------ ------------ ------------ ------------ Balance, December 31, 1997 1,636,785 $ 11,588,073 $ (1,682,864) $ 9,905,209 Stock issued for cash in Reg "S" Offering 12,752 84,446 -- 84,446 Issuance of stock to purchase shares of Saba Petroleum 1,407,000 14,062,500 -- 14,062,500 Net Income (5,547,645) (5,547,645) ------------ ------------ ------------ ------------ Balance as of December 31, 1998 3,056,537 25,735,019 (7,230,509) 18,504,510 Issuance of stock for acquisition of Saba 1,295,425 9,869,904 -- 9,869,904 Issuance of stock for acquisition of Beaver Lake minority Interest 70,977 506,978 -- 506,798 Other issuances, net 133,998 1,149,142 -- 1,149,142 Net Income -- -- 3,367,032 3,367,032 Other Comprehensive Loss -- -- (19,243) (19,243) ------------ ------------ ------------ ------------ Balance as of December 31, 1999 4,556,937 37,261,043 (3,882,720) 33,378,323 Issuance of stock for secondary offering 543,375 6,350,377 -- 6,350,377 Issuance of stock for options and warrants 219,427 1,292,420 -- 1,292,420 Issuance of stock for conversion of debentures 43,534 470,000 -- 470,000 Repurchase of common stock (840,000) (5,737,116) -- (5,737,116) Stock dividend -- 2,907,818 (2,907,818) -- Net Income -- -- 4,457,214 4,457,214 ------------ ------------ ------------ ------------ Balance as of December 31, 2000 4,523,273 $ 42,544,542 $ (2,333,324) $ 40,211,218 ============ ============ ============ ============

2000 1999 1998 ------------ ------------ ------------ Cash Flow operating activities: .................. -- -- -- Net Income (loss) ............................... $ 4,457,214 3,367,032 (5,547,645) Adjustments to reconcile net income (loss) to net cash used inoperating activities Depreciation, depletion, and amortization ................................... 3,592,242 3,023,788 333,468 Writedown of oil and gas properties ............. -- -- 3,171,485 (Gain) loss on sale of assets ................... -- -- (9,223) Equity in net loss of Saba ...................... -- 553,483 586,020 Compensation expense attributable to the issuance of Common Stock ................... -- 150,000 -- Loss on sale of Canadian properties .............. 991,439 -- -- Change in accounting policy ...................... 853,109 -- -- (Increase) decrease in accounts receivable ..................................... (1,453,805) (1,101,994) (3,626) (Increase) decrease in other assets .............. 700,337 (5,126,741) (147,355) (Increase) decrease in inventory and other current assets ................................. (3,625,527) (66,310) (114,646) Increase (decrease) in accounts payable and accrued expenses ................... 5,901,401 (1,179,791) (562,222) Minority Interest in (loss) of Consolidated subsidiary ........................ -- (20,617) -- Decrease in other liabilities .................... (902,611) -- -- ------------ ------------ ------------ Net cash provided by (used in) operating activities ........................... 10,534,280 (401,150) (2,293,744) ------------ ------------ ------------ Cash flow from investing activities: Decrease (increase) in time deposits and funds held in escrow ....................... -- -- (1,613,695) Purchases of property and equipment ............. (13,601,519) (2,091,735) (1,168,519) Proceeds from sale of property and equipment ...................................... 571,000 915,000 55,908 Acquisition of Saba common and preferred shares ............................... -- -- (2,327,630) Cash acquired in Saba acquisition ............... -- 444,764 -- Other ............................................ (56,380) -- ------------ ------------ ------------ Net Cash (used in) investing activities .......... (13,030,519) (788,351) (1,826,546) Cash flows from financing activities: Repayments of Notes Payable ..................... (9,472,277) (28,098,901) (32,896) Proceeds of loans from affiliates ............... -- 25,317,293 2,000,000 Proceeds of Loan ................................ 13,802,414 -- -- Net increase in Revolver Loan .................... -- 4,443,216 -- Payment of financing costs ....................... -- (625,000) -- Proceeds from sale of stock, net of expenses ........................................ 6,350,377 -- 84,446 Repurchase of Common Stock ....................... (5,737,116) -- -- Increase from restricted cash .................... 1,000,000 -- -- Exercise of options .............................. 1,292,420 -- -- ------------ ------------ ------------ Net cash provided by financing activities ........ 7,236,318 1,036,608 2,051,550 ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents ................................ 4,740,380 (152,893) (2,068,740) Cash and cash equivalents: Beginning of period ............................. 97,319 250,212 2,318,952 ------------ ------------ ------------ End of period .................................... $ 4,837,699 $ 97,319 $ 250,212 ============ ============ ============ Cash paid for: Interest ........................................ $ 3,830,243 $ 1,688,424 $ 32,145 Income taxes .................................... $ 197,938 $ 149,282 $ -- Non-cash financing and investing activities: Stock issued for services ....................... $ -- $ (180,000) $ -- Stock issued upon conversion of convertible debentures ......................... 470,000 -- --

Integrated E&P E&P Corp. & Operations Americas Int'l Other Total ------------ ------------ ------------ ------------ ------------ 2000 ---- Total Oil and Gas Revenue $ 10,299 $ 14,851 $ 422 $ (9,915) $ 15,588 Refinery Revenue 33,480 -- -- -- 33,480 ------------ ------------ ------------ ------------ ------------ Total Revenue 43,710 14,851 422 (9,915) 49,068 ------------ ------------ ------------ ------------ ------------ Expenses: Production Costs 2,064 3,993 84 (2,065) 4,077 Refinery Costs 28,985 -- -- (7,862) 21,123 General and Administrative 1,896 1,922 104 2,777 6,699 DD&A Expenses 1,814 1,556 77 145 3,592 Net profit sharing plan -- -- -- 495 495 Other expenses 1,882 -- -- -- 1,882 ------------ ------------ ------------ ------------ ------------ Operating Profit 7,069 7,471 157 (2,910) 11,199 ------------ ------------ ------------ ------------ ------------ Interest expense 2,646 320 27 1,542 4,535 Loss on sale of Canada -- -- 991 -- 991 Income tax expense -- -- -- 362 362 Cumulative effect of accounting change 853 -- -- -- 853 ------------ ------------ ------------ ------------ ------------ Net Income (loss) $ 3,569 $ 7,000 $ 130 $ (6,301) $ 4,457 ============ ============ ============ ============ ============ Capital Expenditures $ 3,452 $ 6,112 $ 1,662 -- $ 11,226 Assets at Year End $ 61,497 $ 31,925 $ 4,642 $ 749 $ 98,813 1999 ---- Total Oil and Gas Revenue $ 3,710 $ 5,425 $ 2,815 $ (3,799) $ 8,183 Refinery Revenue 20,924 -- -- -- 20,924 ------------ ------------ ------------ ------------ ------------ Total Revenue 24,645 5,425 2,868 (3,799) 29,138 ------------ ------------ ------------ ------------ ------------ Production Costs 2,229 2,939 1,577 (3,799) 7,244 Refinery Costs 14,375 -- -- -- 10,576 Gross Profit 7,543 2,487 1,290 -- 11,318 Other Expenses 1,426 245 576 958 3,205 DD&A Expenses 1,453 1,064 506 -- 3,024 Interest and other (expenses) income (31) (31) 747 (2,380) (1,695) ------------ ------------ ------------ ------------ ------------ Net Income (loss) $ 4,630 $ 1,147 $ 955 $ (3,365) $ 3,367 ============ ============ ============ ============ ============ Capital Expenditures $ 2,092 $ 0 $ 0 $ 0 $ 2,092 Assets at Year End $ 58,267 $ 16,886 $ 8,456 $ 244 $ 84,213

Date Consideration Common Stock Preferred Stock Cost ---- ------------- ------------ --------------- ------------ (in 000's) October 1998 Cash 80,000 $ 70 October 1998 Cash 690 750 November 1998 Cash 333,333 1,500 December 1998 1.34 million shares of GREKA 2,971,766 14,070 ---------- --------------- ------------ Total 3,385,099 690 $ 16,390 ========== =============== ============

03/24/99 --------- Refinery $ 25,400 Oil and Gas Properties 29,935 Land 16,600 Other Assets 7,027 Liabilities and minority interest (53,207) --------- Total investment $ 25,755 =========

Year Ended December 31, 1999 ----------------- Dollars in thousands, except share amounts Revenue ........................... $ 32,779 Net Income ........................ 1,459 Income per common share ........... 0.34

2000 1999 ------------ ------------ Investment in limestone properties .......... 3,675,973 3,675,973 Oil and gas property ........................ 38,838,169 29,653,061 Land and buildings .......................... 17,247,744 17,210,814 Plant and equipment ......................... 27,398,506 26,875,661 ------------ ------------ Total cost .................................. 87,160,392 77,415,509 Accumulated depreciation and depletion ...... (9,978,770) (7,128,995) ------------ ------------ $ 77,181,622 $ 70,286,514 ============ ============

2000 1999 ------------ ------------ Net Income ....................................... $ 4,457,214 $ 3,367,032 Add: Income impact of assumed conversion of convertible debt ............... 256,770 241,313 ------------ ------------ Net income plus impact of assumed conversion ..... $ 14,713,984 $ 3,608,345 ============ ============ Weighted Average Common Shares Outstanding ....... 4,262,843 4,002,917 Effect of Dilutive Securities - Employee stock options and warrants .......... 58,609 151,343 Convertible debt ............................. 228,240 420,588 ------------ ------------ Weighted Average Shares plus impact of assumed conversion ........................ 4,549,692 4,574,848 ============ ============

2000 1999 ----------- ----------- Raw Material ........................ $ 368,054 $ 869,735 Finished goods....................... 3,446,938 2,422,645 ----------- ----------- Total ............................ $3,814,992 $3,292,380 =========== ===========

Year Ending December 31: Amount ------------------------ ------- 2001 $ 190,842 2002 175,032 2003 177,616 2004 824

2000 1999 1998 ------------ ------------ ------------ United States ................ $ 4,689,371 $ 2,725,143 $ (5,547,645) International ................ 129,807 687,889 -- ------------ ------------ ------------ $ 4,819,178 $ 3,413,032 $( 5,547,645) ============ ============ ============

2000 1999 ---------- ---------- Current Federal ............... $ 93,787 $ 40,000 State ................. 268,177 46,000 Foreign ............... -- -- ---------- ---------- 361,964 86,000 Deferred Federal ............... -- (40,000) State ................. -- -- Foreign ............... -- -- ---------- ---------- -- (40,000) ---------- ---------- $ 361,964 $ 46,000 ========== ==========

Expires in Amount ---------- ------------ 2008 $ 3,582,000 2009 452,000 2010 64,000 2011 1,067,000 2018 569,000 2019 6,229,000 ------------ Total $ 11,963,000 ============

2000 1999 ------------ ------------ 9% senior subordinated Debentures Due 2005 Net of discount(a) ......................... $ 2,683,933 $ 3,320,778 Loan agreement -(b)..................... 8,700,000 2,986,497 Demand loan agreement with a bank(c) ... -- 794,185 Capital lease obligations(d) ........... 233,437 309,229 Term loan with a bank(e) ............... 340,354 351,562 Notes payable(f) ....................... 2,390,000 2,000,000 15% convertible senior subordinated Debenture due 2001(g) .............. 1,000,000 1,000,000 Term and Revolving Loan Agreement GMAC Financial Corporation(h) ...... 20,904,446 22,219,469 Other notes and loans .................. 639,711 638,086 ------------ ------------ $ 36,891,881 $ 33,619,806 Less current portion ................... 8,685,110 17,923,981 ------------ ------------ Net Long-term debt ..................... $ 28,206,771 $ 15,695,825 ============ ============

2000 1999 1998 ---------- ---------- ---------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price ---------- ---------- ---------- ---------- ---------- ---------- Options outstanding, January 1 .............. 393,750 $ 6.60 420,000 $ 6.70 315,000 $ 4.76 Options granted ......... 1,076,250 $ 8.21 14,700 7.38 262,500 7.86 Options exercised ....... 186,900 $ 5.17 -- -- -- -- Options terminated ...... 172,200 $ 8.21 40,450 7.86 157,500 4.76 ---------- ---------- ---------- ---------- ---------- ---------- Options outstanding, December 31 ............ 1,110,900 $ 8.54 393,950 $ 6.60 $ 420,000 $ 6.70 Exercisable at year end .............. 233,100 $ 8.26 389,550 6.59 31,500 4.76

Number of Warrants Effective Expiration Number of Warrants Granted Option Price Date Date Exercised in 2000 --------- ------------ --------------- ---------------- ------------------ 134,138 $14.29 January 1, 1998 December 1, 2000 502

Number of Warrants Effective Expiration Number of Warrants Granted Option Price Date Date Exercised in 2000 --------- ------------ ---------------- ----------------- ------------------ 105,000 $9.52 February 1, 1999 December 31, 2001 32,025

December 31 ------------------------------------- 2000 1999 1998 ---------- ----------- ---------- Net Income (Loss) as reported $4,457,214 $3,367,032 $(5,547,645) Pro Forma 4,314,824 2,654,911 (6,139,691) Basic EPS as reported $ 1.05 $0.84 $(3.42) Pro Forma basic EPS $ 1.01 $0.66 $(3.78)

Proved developed and undeveloped reserves 2000 1999 1998 ---------------------------- ---------------------------- ------------ Oil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf) Oil (Bbl) ------------ ------------ ------------ ------------ ------------ Balance beginning of the year .......... 10,531,706 17,598,296 250,221 0 2,553,007 Production ............................. (770,007) (1,806,764) (504,961) (861,261) (12,935) Discoveries, extensions, etc. .......... Acquisitions of reserves in place ...... -- -- 10,786,446 18,459,557 -- Sale of reserves in place Revisions of previous estimates ........ 2,250,361 4,283,034 -- -- (2,289,851) ------------ ------------ ------------ ------------ ------------ Balance end of the year ................ 12,012,060 20,074,566 10,531,706 17,598,296 250,221

Capitalized cost 2000 1999 1998 ------------ ------------ ------------ Proven oil and gas property $ 31,318,933 $ 19,812,588 $ 3,445,816 Unproven oil and gas property 7,519,236 2,743,673 -- ------------ ------------ ------------ 38,838,169 22,556,261 3,445,816 Less accumulated depletion (9,970,696) (4,801,051) (3,242,711) ------------ ------------ ------------ Net investment in oil and gas property $ 28,867,783 $ 17,755,210 $ 203,105

Discounted future net cash flows 2000 1999 1998 -------------- -------------- -------------- Future cash flows $ 421,837,100 $ 245,779,700 $ 1,725,500 Future cost: Development cost (28,604,800) (24,109,700) (440,000) Production cost (116,726,900) (107,662,800) (793,700) Future net cash flow before income taxes 276,505,400 114,007,200 491,800 Future income taxes (112,628,500) (46,854,300) (231,100) -------------- -------------- -------------- Standardized measure of discounted future net cash flows $ 163,876,900 $ 67,152,900 $ 260,700

2000 1999 1998 ------------ ------------- ----------- Balance beginning of year $ 67,152,600 $ 260,700 $ 4,610,300 Production Cost 9,064,100 (3,499,657) (17,443) Net Change in prices and production costs 65,890,771 (107,662,800) (3,721,007) Changes in future development cost 4,495,100 24,109,700 4,841,800 Revision of previous quantity estimates 98,956,841 153,918,657 (4,771,053) Accretion of discounts 6,715,260 26,000 861,000 Net change in income taxes (49,945,700) -- 1,751,000 Changes in production rates, timing and other (38,454,072) -- (3,293,897) ------------ ------------- ----------- Standardized measure of discounted future cash flows $163,876,900 $ 67,152,600 $ 260,700

First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- 2000 Sales 9,680,426 13,699,489 12,305,379 13,381,840 Operating Income (loss) 1,906,359 4,319,774 5,802,482 (334,469) Net Income (loss)(1)(2)(3) 25,880 3,535,160 4,640,048 (3,743,874) Diluted earning per common share: Net Income (loss)(1)(2)(3) 0.01 0.80 0.96 (0.73) 1999 Sales 353,102 8,695,456 9,633,912 10,455,340 Operating Income (loss) (502,994) 1,596,964 2,126,456 1,867,705 Net Income (loss) (1,132,542) 1,254,540 1,409,032 1,836,002 Diluted earning per common share: Net Income (loss) (0.38) 0.31 0.33 0.53

Balance at Charged to Charged to Balance Beginning of costs and other at End of Year Period expenses accounts Deductions Period ------ ------------ ---------- ---------- ---------- --------- 2000 $1,343,852 $ $ 827,144 1999 $ 74,000 -- 1,269,852(a) -- 1,343,852 1998 74,092 -- -- (92) 74,000

Signature Title Date /s/ Randeep S. Grewal ---------------------- Randeep S. Grewal Chairman of the Board of April 17, 2001 Directors and Chief Executive Officer (Principal Executive Officer, Financial Officer and Accounting Officer) /s/ Jan F. Holtrop ---------------------- Dr. Jan F. Holtrop Director April 17, 2001 /s/ George C. Andrews ---------------------- George C. Andrews Director April 17, 2001 /s/ Dai Vaughan ---------------------- Dai Vaughan Director April 17, 2001 /s/ Kenton D. Miller ---------------------- Kenton D. Miller Director April 17, 2001

EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 Restated Articles of Incorporation of Horizontal Ventures (filed as Exhibit 3A to Horizontal Ventures' Quarterly Report on Form 10-QSB for the quarter ended June 30, 1998 (File No. 0-20760) and incorporated herein by reference) 3.2 Articles of Amendment to Articles of Incorporation effective March 22, 1999 (filed as Exhibit 3.1 to the Company's Current Report on Form 8-K dated March 15, 1999 and incorporated herein by reference) 3.3 ByLaws of Horizontal Ventures (incorporated by reference to Exhibit No. 3 to the Horizontal Ventures' Registration Statement (#33-24265-LA) 3.4 Amendment to Article II of the Bylaws of GREKA (filed as Exhibit 3.1 to the GREKA Report on Form 10-Q for the Quarter ended September 30, 1999 and incorporated by reference herein) 10.1 Amendment to Promissory Notes dated January 20, 2000 between Greka and International Publishing Holding, Inc. (filed as Exhibit 10.13 to GREKA'S amended Report on Form 10-K filed on April 14, 2000 for the fiscal year ended December 31, 1999, and incorporated by reference herein) 10.2 Beaver Lake Resources Corporation March 1997 Re-Financing Agreement (filed as Exhibit 10.3 to Saba's quarterly report on Form 10-QSB for the quarter ending March 31, 1997 (File No. 001-13880) and incorporated herein by reference) 10.3 Preferred Stock Transfer Agreement dated October 7, 1998 between Horizontal Ventures and RGC (filed as Exhibit 10.1 to Horizontal Ventures' Quarterly Report on Form 10-QSB for the quarter ended September 30, 1998 and incorporated herein by reference). 10.4 Common stock Purchase Agreement dated October 8, 1998 between Horizontal Ventures and Saba (filed as Exhibit 10.2 to Horizontal Ventures' Quarterly Report on Form 10-QSB for the quarter ended September 30, 1998 and incorporated herein by reference). 10.5 Option Agreement dated July 22, 1998 between Horizontal Ventures and IPH (filed as Exhibit 10.3 to Horizontal Ventures' Quarterly Report on Form 10-QSB for the quarter ended September 30, 1998 and incorporated herein by reference). 10.6 Promissory Note dated October 6, 1998 payable by Horizontal Ventures to IPH (filed as Exhibit 10.4 to Horizontal Ventures' Quarterly on Form 10-QSB for the quarter ended September 30, 1998 incorporated herein by reference). 10.7 Pledge Agreement dated October 6, 1998 between Horizontal Ventures and IPH (filed as Exhibit 10.5 to Horizontal Ventures' Quarterly Report on Form 10-QSB for the quarter ended September 30, 1998 and incorporated herein by reference).

Filing Compare · GREKA ENERGY CORP